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CAISO Business Practice Manual BPM for Market Operations
MARKET OPTIMIZATION
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version 42 Last Revised: Page A-1
This information will be provided at a later date in the form of a technical bulletin.
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version 42 Last Revised: September 30, 2014June 2, 2015 Page A-1
Attachment A
MARKET INTERFACES
A. Market Interfaces
This Market Interfaces attachment presents the data exchange between Market applications.
Refer to Section 3.3, Market Interfaces, which shows the inter-relationships of these
applications.
A.1 Scheduling Infrastructure & Business Rules (SIBR) System
The SIBR system performs the following tasks:
Provides an SC interface to submit Bids and Inter-SC Trades
Applies business rules to validate and process submitted Bids and Inter-SC Trades
Applies business rules to generate DAM Bids for Generating Units under the must offer
obligation (Generating Unit adequacy requirement) and Real-Time Market Bids for
Generating Units with Day-Ahead AS or RUC Awards, if these Generating Units do not
have valid Bids
Provides SCs with information about their Bid and trade validation and processing
Forwards the final (clean) Bids and trades to the relevant Market applications and to the
SC
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Stores information for auditing purposes
A.2 Scheduling & Logging of Outages (SLIC)
SLIC only applies to Generating Units and allows Market Participants to notify CAISO when a
Generating Unit’s properties change due to physical problems. Users can modify the maximum
and minimum output of a unit, as well as the Ramping capability of the unit. This data is
accessed directly by the Real-Time processes to override some of the Master File data.
The BPM for Outage Management provides further details on scheduling and maintaining facility
Outages.
A.3 Automated Demand Forecasting System (ALFS)
The elements of ALFS are described in this section.
A.3.1 Integrated Forward Market (Full Network Model)
Requires Day-Ahead and two Days-Ahead Demand Forecasts, in increments of one hour for the
following:
Metered Subsystems (MSSs) – Load forecasts for Load-following MSSs are required.
In addition, if the other MSSs do not provide their own Load forecasts, CAISO provides
one.
Calculated Forecasts – Presently some IOU forecasts include the MSSs. Once the
MSS forecasts become available, the IOU Load forecasts without the MSSs in their area
are used. This is accomplished within ALFS, using software from Itron.
Other Control Areas – Load forecasts for some control areas are necessary because
their detailed networks are included in the Full Network Model. In order to provide the
most accurate forecast, the non-conforming Pumping Load is forecasted separately from
the temperature-sensitive conforming Load.
Load forecast for CFE is desirable, since it is part of the California-Mexico Reliability
Coordination Area. IID has recently joined the WECC Desert Reliability Coordination
Area and thus is not a likely candidate for Load forecasting.
Congestion Zones – In IFM, Congestion zones are not needed except for financial
trades. However, for Ancillary Services, an additional Load forecast is required.
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A.3.2 RMR Preschedule
Requires Day-Ahead forecasts, in increments of one hour for the following:
Local Control Areas (LCAs) – In order to make the RMR preschedules consistent with
the IFM, it is desirable to have the RMR preschedules use the same Load forecasts as
IFM. Therefore, forecasts are needed for existing LRAs defined by Operations
Engineering. One area Load forecast is currently provided by ALFS. Forecasts for the
LRAs may also be used to improve the application of LDFs, since LDFs can be applied
to smaller areas.
A.3.3 LMP Load Zones
Requires Day-Ahead forecasts, in increments of one hour for the following:
LMP Load Zones – At this time, CAISO is not considering LMP for Load forecasting.
A.3.4 ALFS Loss of Data Interfaces
ALFS updates Load forecasts every 15 minutes. In the event of failure to update data, RTM
continues to use the un-updated data. If data does not exist for a particular interval, RTM uses
data from the last available interval or from a CAISO Operator enterable data entry point.
RTM alerts the user when ALFS data has not been updated for 30 minutes (configurable
parameter). RTM also alerts the user when data does not exist for a particular interval.
A.4 Master File
The Master File is a general repository of quasi-static data needed to operate and support the
CAISO Markets. The Master File contains data that remain unchanged for relatively long
periods of time. Relevant Master File data includes:
SC registration and associated attributes
Resource registration, characteristics, Market and product certifications, and associated
attributes such as location, SC association, must offer, or RMR status
Network node and branch registration and associated attributes
Node aggregation definitions (LAPs, Trading Hubs, AS Regions, RUC zones, designated
Congestion areas)
Transmission interface definitions
TOR and ETC registration
Market parameters such as Bid caps and MPM thresholds
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Although SCs do not interface directly with the Master File, they are obligated to provide
accurate data for populating and updating the Master File with their applicable Generating Unit
characteristics, such as minimum and maximum capacity, Forbidden Operating Regions, Ramp
Rates, Minimum Run and Down Times, average heat rates or average production costs. This
requirement is based on Section 4.1.2 of the Pro Forma Participating Generator Agreement
(Appendix B.2 of the CAISO Tariff).
Additional information on the Master File is available on the CAISO web site at:
http://www.caiso.com/docs/2005/10/27/2005102715043129899.html
A.5 Open Access Same Time Information System (OASIS)
The OASIS provides a Web interface for Market Participants to retrieve public Market
information, including:
Demand forecast
AS requirements
Aggregate Schedules
Transmission interface limits and flows
Locational Marginal Prices
Regional Ancillary Services Market Prices
This is described in more detail in Section 13 of the BPM for Market Instruments .
A.6 Settlements & Market Clearing System (SaMC)
SaMC receives Market results from the CAISO Markets and meter data from SCs to perform
Settlement according to specific business rules and charge types. Refer to the BPM for
Settlements & Billing for further information.
A.7 Energy Management System (EMS)
EMS sends control data to units on regulation. It matches electricity Supply and Demand on a
four second basis. EMS has an associated database called PI to store the data.
As part of this functionality, EMS gets telemetry and data from the State Estimator, data from
most units in the CAISO Control Area, and all of the transmission lines interfacing with other
control areas. EMS/PI is the source of this data for the Real-Time processes. EMS is also the
source of the base Full Network Model.
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EMS receives preferred operating point data, representing the economic Dispatch Instruction,
from RTED via the ramp tool. EMS sends this data to units on regulation as a neutral set point.
EMS also receives information on dispatched Ancillary Services, which is used to calculate
Energy reserves for the power system
A.7.1 EMS Loss of Data Interfaces
EMS updates data every 30 seconds. In the event of failure to update data for five minutes,
RTM considers the data obsolete and alerts the user. RTM performs the following actions in the
event of either obsolete or bad quality EMS data (note that data manually replaced in EMS is
not considered to be obsolete or of bad quality):
Marks affected data with a flag on applicable screens
Does not use affected regulating limits from EMS for Ancillary Services and
Supplemental Energy allocation. Instead, uses the limits from the Master File according
to the “next hour’s” allocation.
Does not use affected telemetry for the imbalance MW calculations. Instead, assumes
that the Generating Unit attempts to comply with the DOT starting at the last good
telemetry point using the Generating Unit’s physical Ramp Rate.
A.7.2 State Estimator Failure
A State Estimator and a full AC power flow are run in the EMS in order to create the system
state that is transferred to the RTM system. This information is transferred from the EMS to the
RTM system every 5 minutes and on events that trigger the State Estimator. This data is used
to initialize the network model in the RTM system with the current power system state.
The RTM uses the state of the power system and switch status (switch status received in both
full and incremental modes) to solve the base case power flow.
The RTM uses the most recent SE solution. RTM uses the old solution if a new SE solution
(for a user specified number of intervals) has not been received by the RTM system.
A DC power flow solution is used in case the full AC power flow does not solve in the RTM
system.
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A.8 Automated Dispatch System (ADS)
ADS is an application developed by CAISO to communicate Real-Time Dispatch Instructions to
SCs. As a user of ADS, you are able to:
Receive and generally respond to in-hour Dispatch Instructions in Real-Time
Receive confirmation of accepted pre-Dispatch Instructions
Retain a local record of the transaction
Query a database for historical instructions
SCs are able to accept or decline inter-tie dispatches, or may be able to communicate their
ability to respond to the dispatches. SCs can also use ADS to record control area approval of
intertie dispatches and to push accepted intertie instructions to CAS.
The public Internet is the method of transmitting the instruction and response information
between CAISO and the SC. ADS uses 128-bit domestic encryption and Secure Sockets Layer
(SSL) communications technology, combined with medium assurance digital certificates and
smart cards, to create a secure environment. Detailed logs are maintained by CAISO to assist in
dispute resolution.
A.8.1 ADS Loss of Data Interfaces
In the event of loss of connectivity to ADS, or particular ADS tables, or incorrect flags in
interface tables, RTM alerts the user of a problem, indicates what RTM detects as the problem,
and allows the user to retry connecting to ADS.
If the user cannot restore the connection before any subsequent dispatches, then a means is
provided to continually display the requested Dispatch so that CAISO Operators may manually
Dispatch the resources, or remove resources from the list. When CAISO Operators are finished,
they indicate such to RTM and then RTM writes the results to the Dispatch log. RTM also
records the event in SIBR so that Expected Energy can be recalculated later.
A.9 Control Area Scheduler (CAS)
A detailed description of the interchange transactions and associated tagging is given in Section
6.3.2 for DAM and Section 7.2.2 for RTM.
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A.9.1 CAS Loss of Data Interfaces
The CAS updates Schedules every 5 minutes. In the event of loss of data updates, RTM
continues to use the un-updated data. If data does not exist for a particular hour, RTM uses
data from the last available hour as proxy for following hours.
RTM alerts the user when CAS data has not been updated for 10 minutes (configurable
parameter). RTM also alerts the user when no data exists for a particular hour.
A.10 CAISO Market Results Interface (CMRI)
The CAISO Market Results Interface or CMRI is the reporting interface that contains private
market information resulting from the CAISO Market Processes: MPM, IFM, RUC, and RTM.
This includes schedules and awards, resource specific prices, default and mitigated bids, unit
commitments and instructions.
In addition to those mentioned above, post-market or after-the-fact information such as
Expected Energy (energy accounting results) and the Conformed Dispatch Notice (commonly
known as the “CDN”) can be accessed from the CMRI.
Detailed description of these reports can be found under the BPM Market Instruments Section
11.
A.11 Operational Meter Analysis & Reporting (OMAR) System
The OMAR system performs automated validation of meter readings and pushes Settlement
Quality Meter Data (SQMD) to Settlements. The OMAR system notifies the CAISO Operator if
human attention is required, and provides a user interface display where manual observation,
intervention, and meter data modification can be performed.
A.12 Electronic Tagging System
The electric tagging system provides the means by which SCs can enter/change the e-Tag
information that is required for the interchange of Power transactions between the CAISO
Control Area and other Control Areas. See Section 6.3.2 for e-Tags in the Day-Ahead Market
and Section 7.2.2 for e-Tags in the Real-Time Market.
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A.13 Participating Intermittent Resource Program (PIRP) and Eligible Intermittent Resources (EIRs)
This section is based on CAISO Tariff Sections 4.6.1.1, 4.8, 9.3.10, Appendix F (Rate
Schedules) and Appendix Q (Eligible Intermittent Resources Protocol (EIRP)). All Eligible
Intermittent Resources (EIRs) with a Participating Generator Agreement, Net Scheduled PGA,
Dynamic Scheduling Agreement for Scheduling Coordinators, or Pseudo-Tie Participating
Generator Agreement that, among other things, binds the Eligible Intermittent Resource to
comply with the CAISO Tariff; must comply with the EIRP. The EIRP also sets forth additional
requirements for those EIRs that voluntarily elect to become Participating Intermittent
Resources (PIRs) under the CAISO’s Participating Intermittent Resource program (PIRP). EIRs
are not required to participate in PIRP. PIRs participating in PIRP as of May 1, 2014 and
meeting certain additional requirements, including making an election by June 1, 2014, may
qualify for PIRP Protective Measures. A resource that holds QF status may also elect to receive
PIRP Protective Measures, if qualified to receive such measures, by June 1, 2014. The QF will
be eligible to receive PIRP Protective Measures upon expiration of QF status. Irrespective of
when a specific resource begins receiving PIRP Protective Measures, PIRP Protective
Measures will expire on the sooner of: (a) April 1, 2017; or (b) expiration of the condition that
qualified the resource for receiving PIRP protective measures initially (i.e., the execution of a
new or amended contract for services that addresses the Imbalance Energy settlement or the
addition of equipment that makes the resource physically able to respond to CAISO Dispatch
Instructions).
EIRs must either submit a forecast of output with five-minute granularity and update it every five
minutes, or else use the forecast provided by CAISO’s forecast service provider which is also
produced at a five-minute granularity and updated every five minutes.
An EIR may choose to either self-schedule or submit economic bids. If self-scheduling,
the self-schedule for each 15-minute interval in the FMM and for each 5-minute interval
in RTD is derived from the forecast values. If the unit chooses to submit economic bids,
the upper limit will be based on the forecast values.
Scheduling Coordinator Self Certification to Provide a Power Forecast
An EIR that wishes to submit its own forecast for a resource must be able to certify that it will
provide a state of the art forecast using one of, or a combination of, an internal
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meteorological department, an energy forecast service provider, or a defined alternative
forecasting method/system.
The following Scheduling Coordinator Self Certification to Provide a Wind or Solar Power Forecast letter must be submitted before an SC will be certified to use their own forecast.
Scheduling Coordinator Self Certification to Provide a Wind or Solar Power Forecast
[Entity Letterhead]
[Date]
Attn: Manager, Short Term Forecasting
California Independent System Operator Corporation
250 Outcropping Way
Folsom, CA 95630
Re: Self Certification for the submission of resource level wind and solar power forecasting ability
In accordance with Section 4.8.2.1.1 of the California Independent System Operator Corporation’s (“CAISO”) Tariff, this letter provides [name of Entity]’s notice to the CAISO that it wishes to use its own forecast of the following resource’s[’] output in lieu of the output provided by the CAISO:
<Resource Name> <Resource ID>
<Resource Name> <Resource ID>
[Name of Entity] will be using the following service/technique to provide a wind or solar forecasts:
Forecast Service Provider -- ________________ [provide name of provider]
Internal Meteorology Department
Other Method (please describe technique)
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[name of Entity] certifies that its chosen service/technique will provide a State of the Art forecast, as that term is commonly understood in the utility industry. [name of Entity] also understands that Section of 4.8.2.1.1 of the Tariff requires it to provide at a minimum a three-hour rolling forecast with fifteen- (15) minute granularity, updated every fifteen minutes, and may provide in the alternative a three-hour rolling forecast at five- (5) minute granularity, updated every five minutes. Further, [name of Entity] acknowledges that it may not change the masterfile selection FORECAST_SELECTION flag for the above-listed resource[s] to “SC” until it receives confirmation from the CAISO that it has been certified to provide its own forecast.
Sincerely,
[Name of Entity]
The ISO approves this self-certification.
Manager, Short Term Forecasting
Date
An EIR participating as a PIR that does not receive PIRP Protective Measures
may participate as follows:
Economic bids for all resources can be submitted hourly for use in the fifteen-minute market and the real-time dispatch to award an energy schedule or dispatch different than the resource’s forecast.
The 15-minute schedule will be the sum of the relevant three five-minute forecasts received 37.5 minutes prior to flow.
The real-time dispatch instructed energy for the dispatch will be based on the relevant five-minute forecast received 7.5 minutes prior to flow.
Real-time dispatch instructed energy deviations from the 15-minute schedule divided by three will be settled at the real-time dispatch LMP.
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Uninstructed imbalance energy will be the difference between the meter and the real-time dispatch instruction based upon the forecast from 7.5 minutes prior to flow and will settle at the real-time dispatch price.
An EIR participating as a PIR and also receiving PIRP Protective Measures will receive the
following settlement treatment:
Hourly schedules will be settled using a 90-minute-in-advance forecast.
The resource’s will be settled at the simple average of the five-minute
locational marginal prices.
Deviations between the resource’s actual energy output and the hourly
schedule will be netted over each month. This amount will be settled at the
output-weighted average of five-minute locational marginal prices over the
month.
Regardless of whether a wind or solar EIR elects to become a PIR, the EIRP imposes on EIRs
with PGAs, NS PGAs, Dynamic Scheduling Agreement for Scheduling Coordinators, or
Pseudo-Tie Participating Generator Agreementvarious communication and forecasting
equipment and forecasting data requirements. This section facilitates compliance with the EIRP
by providing additional information for wind EIRs, solar thermal EIRs, and solar photovoltaic
EIRs regarding:
The form of the Letter of Intent (LOI) to become a PIR [EIRP Section 2.2.1];
Data relevant to forecasting, including operational and meteorological data [EIRP
Sections 2.2.3 and 3.1];
Monitoring and communications requirements [EIRP Section 3.2];
Forecasting and communication equipment requirements [EIRP Sections 2.2.3, 6, and
6.2];
Objective criteria for accurate forecasts [EIRP Section 4];
PIRP Export Fee Exemption Certification Process for resources that are subject to PIRP
Protective Measures [EIRP Sections 2.2.5 and 5.3.6]; and
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Forecast Fee [EIRP Section 2.4.1].
A.13.1 Request for PIRP Protective Measures
Scheduling Coordinators for resources that wish to qualify for PIRP Protective Measures pursuant to Section 4.8.3.2 within the three-year transition period must complete their election for PIRP Protective Measures no later than thirty (30) days after the effective date of Tariff Section 4.8.3.
A.13.2 Letter of Intent
The pro forma Letter of Intent (LOI) required by the EIRP for an EIR to become a PIR is set forth
below. The LOI includes the requirement that the proposed PIR submit, as Attachment A to the
letter of intent, a copy of the California Energy Commission’s Renewable Portfolio Standard
(RPS) certification identifying the facility as RPS-eligible.
FORM OF LETTER OF INTENT TO BECOME A
PARTICIPATING INTERMITTENT RESOURCE
[Entity Letterhead]
[Date]
Attn: Project Manager, Model and Contract Implementation
California Independent System Operator Corporation
250 Outcropping Way
Folsom, CA 95630
Re: Intent to become a Participating Intermittent Resource:
In accordance with Section 2.2.1 of the California Independent System Operator Corporation’s (“CAISO”) Eligible Intermittent Resource Protocol (the “Protocol”), this letter provides [name of Entity]’s notice to the CAISO that it intends to become a Participating
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Intermittent Resource (the “Letter of Intent”). [Name of Entity] requests that the CAISO initiate the process of operationally certifying its facilities known as [project name] as a Participating Intermittent Resource. [Name of Entity] agrees that, prior to the date of such certification, it will execute a Participating Generator Agreement [or Net Scheduled Participating Generator Agreement] and a Meter Service Agreement for CAISO Metered Entities as required by Section 2.2.1 of the Protocol and thereafter will pay the Forecast Fee as required by Section 2.4.1 of the Protocol.
Further, [name of Entity] agrees that [project name] will remain a Participating Intermittent Resource for a period of at least [insert number of years greater than or equal to one] year(s) following the date of its certification, over which time the maximum Forecast Fee shall be as specified in Schedule 4 of CAISO Tariff Appendix F in effect as of the date of this Letter of Intent, and that [project name] shall thereafter continue to be a Participating Intermittent Resource unless this Letter of Intent is cancelled with thirty (30) days written notice to the CAISO.
Finally, attached to this Letter of Intent as Attachment A is a copy of the California Energy Commissions’ Renewable Portfolio Standard (RPS) certification identifying [name of facility] as RPS eligible.
Sincerely,
[Name of Entity]
A.13.3 Wind Generator Forecasting and Communication Equipment Requirements
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The requirements set forth in this Section A.13.2 apply to EIRs powered by wind with a PGA or
NS PGA, except as otherwise specified below and whether or not the EIR is certified or seeking
certification as a PIR. The detailed requirements for forecasting and communication equipment
for wind generators are set forth in Appendix Q of the CAISO Tariff..
A.13.3.1 Physical Site Data
As part of an EIRs obligation to provide data relevant to forecasting Energy from the EIR, each
applicable wind EIR or its Scheduling Coordinator (SC) must provide the CAISO with accurate
information regarding the physical site location of the EIR as outlined in Appendix Q of the
CAISO Tariff.. Meteorological and Production Data
Each wind EIR must install and maintain equipment required by the CAISO to support accurate
power generation forecasting and the communication of such forecasts, meteorological data,
and other needed data to the CAISO. The requirements for communication of such data to the
CAISO are set forth in Appendix Q of the CAISO Tariff.
The objective of this requirement is to ensure a dataset that adequately represents the
variability in wind velocity within the plant. Where individual EIRs have circumstances that
prohibit them from reasonably satisfying this requirement, the CAISO, the forecast service
provider, and the wind-plant owner will formulate a cost-effective distribution of Designated
Turbines by mutual agreement that approximates this requirement and adequately measures
the variability of the wind velocity within the EIR. EIRs seeking a variance from this requirement
should do so in the development of their interconnection agreement or, for those EIRs that have
already finalized an interconnection agreement, as part of entering into a Meter Service
Agreement.
Wind data collected at the nacelle will not represent the true wind value at a plant site, but
instead will represent the apparent wind, which can be correlated to the co-located turbines.
This requirement will help ensure: (a) multiple data streams for anemometer information; and (b)
accurate representation of the data points to calculate wind energy production at the park.
Wind EIRs with a PGA or NS PGA that are operating or have final regulatory approvals to
construct as of the effective date of this section that have wind turbines without nacelle
anemometers need not comply with the requirements of this section for Designated Turbines.
An EIR that does not provide the meteorological data required in Appendix Q of the CAISO
Tariff will be informed in writing of its failure to provide such required data. Failure to begin
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providing the required information in the time specified in the written notice will result in the
resource participating in the market as a non-EIR resource.
A.13.3.2 Training of Neural Network
High quality1 production and meteorological data must be collected for a minimum of thirty (30)
consecutive days before the ISO can produce a forecast. This data must be collected in
advance in order to train the forecast models (e.g., artificial neural networks) responsible for
producing the power production (MW) forecast for each site.
A.13.3.3 Maintenance & Calibration
Meteorological equipment should be tested and, if appropriate, calibrated: (1) in accordance
with the manufacturer’s recommendations; (2) when there are indications that the data are
inaccurate; or (3) when maintenance has been performed that may have interrupted or
otherwise adversely impacted the accuracy of the data. The ISO will report in writing to the
relevant SC those sites that are sending poor quality meteorological or real time production
data. Failure to begin providing adequate data in the time specified in the written notice will
result in the resource participating in the market as a non-EIR resource.
A.13.4 Solar Generator Forecasting and Communication Equipment Requirements
The requirements set forth in this Section A.13.3 apply to solar thermal and solar photovoltaic EIRs with a PGA or NS PGA, except as otherwise specified below and whether or not the EIR is certified or seeking certification as a PIR. The detailed requirements for
1 Data quality must be adequate to produce a state of the art forecast as determined by a forecast service provider. For example temperatures and wind speeds far exceeding local norms or real time MW production with no wind speed or irradiance would be an example of poor data quality.
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forecasting and communication equipment for solar thermal and solar photovoltaic generators are set forth in Appendix Q of the CAISO Tariff.
A.13.4.1 Physical Site Data
As part of an EIR’s obligation to provide data relevant to forecasting Energy from the EIR, solar
thermal and solar photovoltaic EIRs or their Scheduling Coordinators (SCs) must provide the
CAISO with an accurate description of the physical site of the EIR as outlined in Appendix Q of
the CAISO Tariff..
A.13.4.2 Meteorological and Production Data
Each solar thermal and solar photovoltaic EIR must install and maintain equipment required by
the CAISO to support accurate power generation forecasting and the communication of such
forecasts, meteorological data, and other needed data to the CAISO. An EIR that does not
provide the meteorological data required in Appendix Q of the CAISO Tariff will be informed in
writing of its failure to provide such required data. Failure to begin providing the required
information in the time specified in the written notice will result in the resource participating in
the market as a non-EIR resource.
A.13.4.3 Training of Neural Network
High quality2 production and meteorological data must be collected for a minimum of thirty (30)
consecutive days before the ISO can produce a forecast. This data must be collected in
advance in order to train the forecast models (e.g., artificial neural networks) responsible for
producing the power production (MW) forecast for each site.
A.13.4.4 Maintenance & Calibration
Meteorological equipment should be tested and, if appropriate, calibrated: (1) in accordance
with the manufacturer’s recommendations; (2) when there are indications that the data are
2 Data quality must be adequate to produce a state of the art forecast as determined by a forecast service provider. For example temperatures and wind speeds far exceeding local norms or real time MW production with no wind speed or irradiance would be an example of poor data quality.
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inaccurate; or (3) when maintenance has been performed that may have interrupted or
otherwise adversely impacted the accuracy of the data. The ISO will report in writing to the
relevant SC those sites that are sending poor quality meteorological or real time production
data. Failure to begin providing adequate data in the time specified in the written notice will
result in the resource participating in the market as a non-EIR resource.
A.13.5 Forced Outage Reporting
The additional Forced Outage reporting requirements imposed on EIRs under CAISO Tariff Sections 9.3.10.3 and 9.3.10.3.1 are intended to enhance the CAISO’s ability to produce accurate forecasts of the EIR output.
A.13.6 Participating Intermittent Resource Export Fee Exemption Certification Process
The provisions governing the Participating Intermittent Resource Export Fee are found at
CAISO Tariff, Appendix Q, EIRP Section 5.3 and Appendix F, Schedule 4. In accordance with
these provisions, the Participating Intermittent Resource Export Fee applies only to Participating
Intermittent Resources that have elected PIRP Protective Measures and does not apply to resources that
have not elected for such measures.
The owner of a PIR, as of November 1, 2006, utilizes the Energy generated from the
Participating Intermittent Resource to meet its own Native Load outside the CAISO Balancing
Authority Area.
The PIR has an export contract with a starting term prior to November 1, 2006.
The PIR has a contract to sell Energy to a Load Serving Entity with Native Load in the CAISO
Balancing Authority Area.
The purpose of this Section A.14.6 is to describe the steps necessary to submit the certifications
described in EIRP Sections 2.2.5 and 5.3 required to determine the PIR Export Percentage for
applicable PIRs.
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A.13.6.1 Participating Intermittent Resource Export Fee Exemption Certification Required Documentation
To complete the requirements set forth in EIRP Sections 2.2.5 for a certification for exemption from the Participating Intermittent Resource Export Fee, the following items must be included:
1) Certification Form (see Section A.13.6.6 below) must include: a. Name and address of the Participating Intermittent Resource b. The amount, in MW, for each exemption category c. Calculation of PIR Export Percentage d. Signature of officer for the Participating Intermittent Resource
2) Copies of all executed contracts, including changes, supporting the exemptions listed in the certification form. Price information may be redacted from the contracts provided, however, that the CAISO must be able to determine from the contract the identity of the purchaser, quantity purchased, and the length of term of the contract for the PIR.
Submittal Address
Send a signed hard copy of the certification form and copies of all relevant contracts to the following address:
California ISO Attn: Julia Payton 250 Outcropping Way Folsom, CA 95630
A.13.6.2 CAISO Feedback
Within 30 days of receipt of the completed certification form and submitted contracts, the CAISO
will provide written confirmation that the Participating Intermittent Resource has satisfied the
requirements under EIRP Section 2.2.5. The CAISO will provide the Participating Intermittent
Resource with its PIR Export Percentage and the applicable exemption period ending date that
has been validated based on the contracts submitted.
The PIR Export Percentage will remain valid until the exemption period ending date unless the
Participating Intermittent Resource alters the composition of the resource, changes the PMax of
the resource, or changes the purchaser, quantity purchased, or length of the term of the
contracts for the PIR.
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A.13.6.3 Resubmission of Certification
The Participating Intermittent Resource Export Fee exemption certification must be updated by
resubmission to the CAISO:
1) Upon a request to modify the composition of the Participating Intermittent Resource under EIRP Section 2.4.2, or
2) Within ten (10) calendar days of the final execution of a new contract or any change in counterparty, start and end dates, delivery point(s), quantity in MW, or other temporal terms for any prior certified contract. All other contractual changes will not trigger the obligation for recertification.
A.13.6.4 Example of PIR Export Percentage Calculation
A PIR with a 100 MW PMax has 2 contracts: (1) a contract executed on January 1, 2005 to
export 55 MW to a Balancing Authority Area outside the CAISO Balancing Authority Area; (2) a
contract executed on January 1, 2007 to sell 20 MW to a load serving entity in the CAISO
Balancing Authority Area. Such facility would fill the table in the certification form as follows:
Table 4 Portion of Participating Intermittent Resource Capacity (in MW)
Exemption Category
0 EIRP Section 5.3.1 (a): The owner of a Participating Intermittent Resource, as of November 1, 2006, utilizes the Energy generated from the Participating Intermittent Resource to meet its own Native Load outside the CAISO Balancing Authority Area.
55 EIRP Section 5.3.1 (b): The Participating Intermittent Resource demonstrates … an export contract with a starting term prior to November 1, 2006.
20 EIRP Section 5.3.1 (c): The Participating Intermittent Resource demonstrates … a contract to sell Energy to a load serving entity with Native Load within the CAISO Balancing Authority Area.
75 Total MW eligible for Participating Intermittent Resource Export Fee exemption
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The PIR Export Percentage would be calculated as follows:
PIR Export Percentage = (PMax of PIR – Total MW eligible for Participating Intermittent Resource Export Fee exemption) / PMax of PIR
For example, if PMax of PIR = 100 MW, Total MW eligible for Participating Intermittent Resource Export Fee exemption = 75 MW then PIR Export Percentage = (100-75)/100 = 25% A.13.6.5 Annual Certification
EIRP Section 5.3.6 provides that by December 31 of each calendar year, each Participating
Intermittent Resource shall confirm on the form set forth in a BPM, signed by an officer of the
Participating Intermittent Resource, that the operations of the Participating Intermittent
Resource are consistent with any certification(s) provided to the CAISO under EIRP Section
2.2.5. The certification form to be submitted to meet this requirement is set forth in Section
A.13.6.6.
A.13.6.6 CERTIFICATION FORM FOR THE PARTICIPATING INTERMITTENT RESOURCE EXPORT FEE EXEMPTION
Company letterhead
Date
Participating Intermittent Resource Name:
CAISO Resource ID:
Address of principal place of business
Street:
City:
State: Zip Code:
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In accordance with Section 2.2.5 [and/or 5.3] of the California ISO’s Eligible Intermittent Resources Protocol (“EIRP”), this letter provides certification that PIR NAME is eligible for the following Participating Intermittent Resource Export Fee exemptions:
Table 5
Portion of Participating Intermittent Resource Capacity (in MW)
Exemption Category
[0]
EIRP Section 5.3.1 (a): The owner of a Participating Intermittent Resource, as of November 1, 2006, utilizes the Energy generated from the Participating Intermittent Resource to meet its own Native Load outside the CAISO Balancing Authority Area.
[0] EIRP Section 5.3.1 (b): The Participating Intermittent Resource demonstrates … an export contract with a starting term prior to November 1, 2006.
[0]
EIRP Section 5.3.1 (c): The Participating Intermittent Resource demonstrates … a contract to sell Energy to a load serving entity with Native Load within the CAISO Balancing Authority Area.
[0] Total MW eligible for Participating Intermittent Resource Export Fee exemption
According to the table above and based on the Participating Intermittent Resource PMax, the estimated PIR Export Percentage is calculated as:
(PMax of PIR – Total MW eligible for Participating Intermittent Resource Export Fee exemption) / PMax of PIR = ___ %
This certification must be updated by resubmission to the CAISO (1) upon a request to modify the composition of the Participating Intermittent Resource under EIRP Section 2.4.2 or (2) within ten (10) calendar days of the final execution of a new contract or any change in counterparty, start and end dates, delivery point(s), quantity in MW, or other temporal terms for any prior certified contract. All other contractual changes will not trigger the obligation for recertification.
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I hereby acknowledge that I am an officer of the Participating Intermittent Resource who has sufficient authority to execute this document on behalf of PIR NAME.
Authorized Signature: ________________________________
Name:
Title:
A.13.7 Forecast Fee
Beginning on the date first operational, a EIR with a PGA or QF PGA must pay the Forecast Fee for all metered Energy generated. Notwithstanding the foregoing, the following exemption from the Forecast Fee applies:
1. EIRs meeting all of the following criteria: (a) has a Master File PMax of less than 10 MW, (b) it sold Energy under the terms of a PURPA power purchase agreement before operating pursuant to a PGA or NS PGA, and (c) it is not a PIR.
The amount of the Forecast Fee shall be determined so as to recover the projected annual
costs related to developing Energy forecasting systems, generating forecasts, validating
forecasts, and monitoring forecast performance, that are incurred by the CAISO as a direct
result of participation by EIRs in CAISO Markets, divided by the projected annual Energy
production by all EIRs.
The current rate for the Forecast Fee is $ 0.10 per MWh.
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A.13.8 Wind and Solar EIR Short Term Forecasting
A.13.8.1 The ISO Automatic Load Forecasting System (ALFS) is configured to provide a day ahead (twenty four hourly forecasts) and short-term (5 minute) forecasts of wind generation and solar plant generation by resource. Two separate forecasts can be provided for each resource. The two forecasts are:
A.13.8.2 External Forecast (EXFC). This is an externally sourced forecast that is provided to the ISO. The forecast time resolution is hourly for the day ahead at the 5 minute level. The forecast will be for seven rolling hours, rolling updated every five minutes. This forecast will be provided for every EIR.
A.13.8.3 Scheduling Coordinator Forecast (SCFC). This is the forecast provided to the ISO by the certified SC. The SC must provide at a minimum a three-hour rolling forecast with fifteen- (15) minute granularity, updated every fifteen minutes, and may provide in the alternative a three-hour rolling forecast at five- (5) minute granularity, updated every five minutes. If a Scheduling Coordinator for an Eligible Intermittent Resource in the CAISO Balancing Authority Area opts to provide the forecast at a five-minute granularity, the CAISO will use the average of the projected Energy output for the relevant three five (5)-minute forecasts to determine the Variable Energy Resource Self-Schedule for the Fifteen Minute
Market. A Scheduling Coordinator forecast may not be available for every wind or solar resource.
Should either forecast appear to interfere with reliable grid operations, in the judgment of ISO operation, the forecasts may be overridden. See Market Operations for BPM for details
A.13.9 Missing Scheduling Coordinator Forecasts
A.13.9.1 The external forecast will replace the Scheduling Coordinator forecast for consumption of the downstream systems in the following cases:
Should the Scheduling Coordinator forecast not be delivered.
The Scheduling Coordinator opts not to provide a forecast.
For periods beyond those submitted by the Scheduling Coordinator up to the
forecast will be provided from the external forecaster,
Attachment B
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COMPETITIVE PATH ASSESSMENT
B. Competitive Path Assessment
The Dynamic Competitive Path Assessment used for Local Market Power Mitigation is
described in section B.1 below. In cases where the Dynamic Competitive Path Assessment is
unable to function, and when evaluating mitigation for exceptional dispatches in real-time, a
default Competitive Path Assessment list is used instead for mitigation. The process for
compiling this list is described in section B.2 below.
B.1 Dynamic Competitive Path Assessment (DCPA)
B.1.1 Accounting For Resource Control
The purpose of a pivotal supplier test is to determine whether one or more suppliers defined on
a portfolio basis can influence market prices through withholding. In the Day-Ahead Market,
combining physical and net virtual supply that correspond to a single supplier is necessary to
accurately account for the extent of withholding and resulting market impact. By comparison, in
the HASP and RTUC, the extent of withholding and resulting market impact is determined
based solely on the physical supply, because there is no virtual supply in those markets. The
aggregation of related resources is referred to as a portfolio for purposes of conducting the
pivotal supplier test - the potential that one or more suppliers' portfolios may be withheld and
have an impact on the market.
Resources will be assigned to a supplier’s portfolio based on the Scheduling Coordinator who
owns the SCID assigned to the resource unless a different Scheduling Coordinator, or an
Affiliate of a different Scheduling Coordinator, controls the resource. Then the resource will be
excluded from the portfolio of the Scheduling Coordinator who owns the SCID assigned to the
resource. The resource will be added to the supplier portfolio of the Scheduling Coordinator
who controls the resource or whose Affiliate controls the resource.
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Furthermore, Scheduling Coordinators who are registered with the ISO as distinct legal entities
(or companies) may be or have Affiliates. The supplier portfolios of affiliated Scheduling
Coordinators will be combined in order to accurately account for the extent of possible
withholding and resulting market impact.
Please refer to the BPM for Scheduling Coordinator Certification and Termination information on
Scheduling Coordinator obligations to report Affiliates and resource control agreements.
B.1.1.1 Resources And Suppliers Considered
1. Resources
a. Day-Ahead Market
All resources that are available will be considered, whether committed or not.
b. HASP
Only resources which are either on-line or offline and have a startup time of 60
minutes or less will be considered.
c. RTUC
Only resources which are either on-line or offline and have a startup time of 15
minutes or less will be considered.
2. Net Sellers as Potentially Pivotal Suppliers:
For determination of the top three potentially pivotal suppliers:
The supplier portfolios of net sellers of electricity will be considered.
Net buyers of electricity do not have an incentive to exercise local market power and
increase spot wholesale prices.
Identification of net buyers to exclude from the set of potentially pivotal suppliers will
be determined quarterly. It will be determined by subtracting metered supply from
the metered demand of each supplier portfolio over the most recent 12 month period.
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SCs without physical resources, for example purely financial SCs, cannot be deemed
net buyers per the definition of net buyer in CAISO Tariff section 39.7.2.2 and
therefore will always be categorized as net sellers.
3. Cleared Convergence Bids included (not applicable for real-time)
Cleared virtual supply bids are included in the demand for counterflow and effective
supply calculations for fringe competitive suppliers.
B.1.2 Process Flow For The Dynamic Competitive Path Assessment (DCPA) In The Day Ahead Market:
1. The DCPA will determine which constraints are competitive and which constraints are non-competitive for each hour of the IFM. The DCPA will be assessed as part of the MPM process prior to the IFM market.
2. For each congested Transmission Constraint k, calculate the total demand for counterflow (DCF) (the default constraint direction being the market AC run flow) :
DCFk = i -SFk,i * Cleared Schedule MWi
for physical resources and virtual supply resources i with negative SFk,i more negative than a threshold (referred to as DCPA Threshold); where Cleared Schedule MWi is the energy schedule for physical or virtual supply resource i.
The energy supply from pump storage and NGR LESR resources shall be included in the counter flow calculation. The demand side of pump storage and NGR LESR resources shall be excluded from the flow calculation. The NGR DDR, pseudo generators associated with PDR/ RDRP/Dispatched Pump resources and NGR DDR shall be excluded from the flow calculation. The external resources will be excluded from the flow calculation.
3. For each congested Transmission Constraint k, and supplier, j, calculate the total available effective supply that can be withheld. This withheld capacity (WC) is:
WCk,j = i(-SFk,i * ENGYMAXi) + i SVCFk,j,i
for resources, i in supplier portfolio, j with negative SFk,i more negative than the DCPA Threshold
Where ENGYMAXi = min[(MAXCAPi – ORi – RUi),(MAXECONi - ORi)]
MAXCAPi = min[(PMAXi – DERATEi), Maximum exceptional dispatch]
MAXECONi = min[(PMAXi – DERATEi), Maximum exceptional dispatch point, Max economic bid MW]
PMAXi is regulation Pmax if on regulation otherwise operational Pmax
ORi is self scheduled spinning and non-spinning reserves
RUi is sef scheduled regulation up
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Note that for MSG Plants the SF is given per plant aggregate connectivity node, and the above calculations involve plant level maximums and derates. The withheld capacity calculation shall not consider pump storage resources, pseudo generators associated with PDR/ RDRP/Dispatched Pump resources, NGR LESR and NGR DDR.
SVCFk,j,i=-SFk,i * DOPi
for virtual resources, i, in supplier portfolio, j, with negative SFk,i more negative than the DCPA Threshold. DOPi is the cleared virtual supply MW for virtual resource i.
The external resources will be excluded from the withheld capacity calculation.
4. For each binding Transmission Constraint k, suppliers are ranked on WCk,j from highest to lowest and the top three suppliers are identified as the set of potentially pivotal suppliers (PPS) for that constraint.
5. The fringe competitive suppliers (FCS) for the constraint k are the portfolios of net buyers and net sellers’ resources that do not belong to PPS for constraint k
6. Calculate the effective supply of physical counterflow (SPCF) for fringe competitive
supplier: SPCFFCS
k,j,i = -SFk,i * ENGYMAXi
The energy supply from pump storage and NGR LESR resources shall be included in the counter flow calculation. The demand side of pump storage and NGR LESR resources shall be excluded from the flow calculation. The NGR DDR, pseudo generators associated with PDR/ RDRP/Dispatched Pump resources and NGR DDR shall be excluded from the flow calculation.
7. Calculate cleared Virtual supply counterflow SVCFFCSk,j,i = -SFk,i * DOPi for each FCS.
8. Combine the supply of physical counterflow and the supply of virtual counterflow for each FCS: SCFFCS
k,j,i = SPCFFCSk,j,i + SVCFFCS
k,j,i
SCFFCSk = Σj Σi SCFFCS
k,j,i
9. Calculate RSI: RSIk = (SCFFCSk ) / DCFk
10. K is deemed uncompetitive (NC) if residual supply index RSIk < 1
11. Apply for each binding Transmission Constraint k. The CPA will be applied only to those paths binding in the MPM run.
12. Apply for each hour. Only paths that are tested and fail the pivotal supplier test will be designated as noncompetitive (NC) on an hourly basis.
B.1.3 Process Flow For The Dynamic Competitive Path Assessment (DCPA) In The Real-Time Market:
The following applies for the DCPA in both the HASP and RTUC runs.
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1. Calculate Withheld Capacity (WCk,j ) for the units (i) that are net suppliers (j) and Shift Factor SFk,i < threshold (default -0.02) for the congested constraint k;
WCk,j = Σi -SFk,i * [ min ( (Popti + RRi * 15) , ENGYMAXi ) –
max ( (Popti - RRi * 15) , ENGYMINi )]
Popti is resource i’s dispatch operating point from the previous interval
RRi is resource i’s ramp rate in MW/minute
Where ENGYMAXi = MIN[(MAXCAPi – ORi – RUi), (MAXECONi – ORi )]
MAXCAPi = min[(PMAXi – DERATEi), Maximum exceptional dispatch]
MAXECONi = min[(PMAXi – DERATEi),Max economic bid MW, Maximum exceptional dispatch]
PMAXi is regulation Pmax if on regulation otherwise operational Pmax
For HASP, ORi is (HASP qualified self-scheduled spinning including transferred DA spin capacity)+ (HASP qualified self-scheduled non-spinning including transferred DA non-spinning capacity)
For RTUC, ORi is awarded spinning capacity + awarded non-spinning capacity
RUi is HASP qualified self-scheduled regulation up including transferred DA regulation up capacity
RRi is the effective ramp rate at Popt (in case of dynamic ramp rate)
Where ENGYMINi = max[(MINCAPi + RDi), Self-scheduled energy]
MINCAPi =max [(Pmini +Pmin RERATEi), minimum exceptional dispatch]
PMINi is regulation Pmin if on regulation otherwise operational Pmin
RD is HASP qualified self-scheduled regulation down including transferred DA regulation down capacity
In HASP, for a unit that is offline in the previous interval and has a startup time of 60 minutes or less, then WC = Pmin. For RTUC, the startup time to be used will be reduced to 15 minutes or less.
The withheld capacity calculation shall not consider pump storage resources, Demand Response Resources, or NGR.
For MSGs only the MSG configuration that is committed is taken into account.
In short, the Withheld Capacity is the Upper Limit a unit could reach from the initial MW to the corresponding interval considering ramping constraint, de-rate etc.
2. Rank (WCk,j) from highest to lowest, the top three suppliers are identified as the set for the potentially pivotal suppliers (PPS) for the constraint k
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3. Calculate supply of counterflow from FCS, for each binding constraint k in any four of 15 minute intervals
SPCFFCSk,j,i = -SFk,i * min (LDOPi + RRi * 15) , ENGYMAXi )
SPCFFCSk,j = ∑i SPCFFCS
k,j,i
SPCFFCSk = ∑j SPCFFCS
k,j
SCFFCSk = SPCFFCS
k
4. Calculate PPS: SPCFPPS
k,j,i = -SFk,i * max ( LDOPi - RRi * 15) , ENGYMINi )
SPCFPPSk,j = ∑i SPCFPPS
k,j,i
SPCFPPSk = ∑j SPCFPPS
k,j
SCFPPSk = SPCFPPS
k
5. Calculate Demand for counterflow: DCFk = ∑i -SFk,i * DOPi 6. Calculate RSI for k:
RSIk = ( SCFPPSk + SCFFCS
k ) / DCFk
7. K is deemed uncompetitive if RSIk < 1 for the trading hour 8. Apply same process to each k
B.2 Default Competitive Path Assessment list
The default competitive path assessment (default CPA) list will be used in order to determine
whether exceptional dispatches are related to a non-competitive Transmission Constraint for
purposes of mitigation of the exceptional dispatches in real-time.
In addition, the default CPA list will be used as a back-up measure in the event that a failure of
the CAISO’s market software prevents the software from performing the DCPA portion of the
LMPM process. The default CPA list will be used in lieu of the dynamically produced list.
Methodology:
The default CPA will be calculated based on following methodology:
Subject to the exceptions discussed below, a Transmission Constraint that passes the following
two thresholds will be deemed competitive for purposes of (1) mitigating exceptional dispatches
in real-time and (2) determining whether the Transmission Constraint is competitive in the event
of a failure of the CAISO’s market software. Otherwise, the Transmission Constraint will be
deemed non-competitive.
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Congestion Threshold: Congested in 10 or more hours in the run where the dynamic
competitive path assessment is calculated, and
Competitive Threshold: Deemed competitive in 75 percent or more of the instances
where the constraint was binding when tested.
Input data will reflect the most recent 60 days of trade dates available at the time of testing.
An exception to the thresholds described above will apply to Path 15 and Path 26. Each of
these two paths will be considered competitive unless the Transmission Constraint was
congested in 10 or more hours in the test period and was deemed competitive less than 75
percent of the time. This exception allows these major inter-zonal interfaces to remain
competitive even when they have not been binding in the past 60 days.
The CAISO will create separate lists of competitive Transmission Constraints for the Day-Ahead
and Real-Time processes, based on data relevant to each market. For the Real-Time Market, if
the Transmission Constraint was binding during any 15-minute interval during an hour, then the
Transmission Constraint will be deemed to be binding for the entire hour. If the Transmission
Constraint was determined to be non-competitive during any 15-minute interval during an hour,
then the Transmission Constraint will be deemed to be non-competitive for the entire hour.
This set of designations will be updated not less frequently than every seven days to reflect
changes in system and market conditions.
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Attachment C
EXPECTED ENERGY CALCULATION
C. Expected Energy Calculation
C.1 Expected Energy Definition
Expected Energy is the total Energy that is expected to be generated or consumed by a
resource, based on the Dispatch of that resource, as calculated by the Real-Time Market
(RTM), and as finally modified by any applicable DOP corrections. Expected Energy includes
the Energy scheduled in the Integrated Forward Market and it is calculated “after-the-fact,” i.e,
after the Operating Day. Expected Energy is calculated for Generating Units, System
Resources, Resource-Specific System Resources, Non-Generator Resources, and Participating
Loads (e.g, pumps). The calculation is based on the Day-Ahead Schedule and the Dispatch
Operating Point (DOP) trajectory for the three-hour period around the target Trading Hour
(including the previous and following hours), the applicable Real-Time LMP for each Dispatch
Interval of the target Trading Hour, and any Exceptional Dispatch Instructions. All Dispatch
Intervals are five minutes in duration.
For energy categories Real-Time Minimum Load Energy, Real-Time Pumping Energy, Derate
Energy, Exceptional Dispatch Energy, and Optimal Energy, separate expected energy
calculations are made for the Fifteen-Minute Market (FMM) dispatch and Real-Time Dispatch
(RTD). These are denoted with a subscript, i.e. OE15 denotes Optimal Energy from the FMM
dispatch and OE5 denotes Optimal Energy from the RTD.
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The following is a list of Expected Energy types and their general descriptions. How each are calculated is described in Section
D.3, Expected Energy Calculation.
Expected Energy Category
Definition Published
Enumeration
Day-Ahead Scheduled Energy (DASE)
Hourly Energy that corresponds to the flat hourly Day-Ahead Schedule (DAS). It is composed of Day-Ahead Minimum Load Energy, Day-Ahead Self-Scheduled Energy, and Day-Ahead Bid Awarded Energy. It does not include the DA Energy that corresponds to the flat schedule when resource is committed in DA pumping mode. Expected energy in DA pumping mode is accounted for as DA pumping energy. Day-Ahead Scheduled Energy includes the DA Energy that corresponds to the negative schedule when the non-generator resource is dispatched to consume energy (i.e. charging). Day-Ahead Scheduled Energy is settled at the IFM LMP as specified in Section 11.2.1.1. of the CAISO Tariff.
DASE
Day-Ahead Minimum Load Energy (DAMLE) [This only includes IFM Min load Energy]
DASE below the registered Minimum Load; it applies to Generating Units with non-zero Minimum Load. DAMLE will be zero for non-generator resources in the initial base model. DAMLE is paid the Day-Ahead LMP as reflected in Section 11.2.1.1 of the CAISO Tariff and it is included in Bid Cost Recovery (BCR) at the relevant DA Minimum Load Cost (MLC) as reflected in Section 11.8.2.1.2 of the CAISO Tariff.
DMLE
Day-Ahead Self Scheduled Energy (DASSE)
DASE above the higher of the registered Minimum Load and below the lower of the Day-Ahead Total Self-Schedule (DATSS) or the DAS. The DATSS is the sum of all Day-Ahead Self-Schedules (except Pumping Self-Schedules) in the relevant Clean Bid. DASSE is paid the Day-Ahead LMP as reflected in Section 11.2.1.1 of the CAISO Tariff and as indicated in Section 11.8.2.1.5 of the CAISO Tariff. It is not included in BCR.
DSSE
Day-Ahead Bid Awarded Energy (DABAE)
DASE above the DATSS and below the DAS. DABAE is also indexed against the relevant DA Energy Bid and sliced by Energy Bid price. The DABAE slices are paid the Day-Ahead LMP as reflected in Section 11.2.1.1 of the CAISO Tariff and they are included in BCR at the cost of the relevant DA Energy Bid
DABE
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Expected Energy Category
Definition Published
Enumeration
prices as shown in Section 11.8.2.1.5 of the CAISO Tariff.
Day-Ahead Pumping Energy (DAPE)
Negative DASE consumed by Pumped-Storage Hydro (PSH) and Pump Resources Scheduled in pumping mode in DA. When DAPE is present, there are no other DASE subtypes present. DAPE is charged the Day-Ahead LMP as reflected in Section 11.2.1.3 of the CAISO Tariff and it is included in BCR at the relevant DA Pumping Cost as demonstrated in Section 11.8.2.1.4 of the CAISO Tariff.
DAPE
Standard Ramping Energy (SRE)
IIE produced or consumed in the first two and the last two Dispatch Intervals due to hourly schedule changes. SRE is a schedule deviation along a linear symmetric 20-min ramp (“standard ramp”) across hourly boundaries. SRE is always present when there is an hourly schedule change, including resource Start-Ups and Shut-Downs. SRE does not apply to Non-Dynamic System Resources (including Resource-Specific System Resources. SRE is not subject to settlement as shown in Section 11.5.1 of the CAISO Tariff.
SRE
Ramping Energy Deviation (RED)
IIE produced or consumed due to deviation from the standard ramp because of ramp constraints, Start-Up, or Shut-Down. RED may overlap with SRE, and both SRE and RED may overlap with DASE, but with no other IIE subtype. RED may be composed of two parts: a) the part that overlaps with SRE whenever the DOP crosses the SRE region; and b) the part that does not overlap with SRE. The latter part of RED consists only of extra-marginal IIE contained within the hourly schedule change band and not attributed to Exceptional Dispatch or derates. RED does not apply to Non-Dynamic System Resources (including Resource-Specific System Resources). RED is paid/charged the Real-Time LMP as reflected in Section 11.5.1 of the CAISO Tariff and it is included in BCR only for market revenue calculations as reflected in Section 11.8.1.4.5 of the CAISO Tariff.
RED
Residual Imbalance Energy (RIE)
Extra-marginal IIE produced or consumed at the start or end of a Trading Hour outside the hourly schedule-change band and not attributed to Exceptional Dispatch. RIE is due to a Dispatch Instruction in the Trading Hour before the
RE
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Expected Energy Category
Definition Published
Enumeration
current Trading Hour or a Dispatch Instruction in the Trading Hour after the current Trading Hour. RIE may overlap only with DASE. RIE does not apply to Non-Dynamic System Resources (including Resource-Specific System Resources.) RIE is settled as bid, based on the RT Energy Bid of the reference hour, or at the Real-Time LMP if there is no Bid as reflected in Section 11.5.1 of the CAISO Tariff, and it is not included in BCR as reflected in Section 11.8.4 of the CAISO Tariff. The reference hour is 1) the Trading Hour before the current trading hour that causes the residual energy, if RIE occurs at the start of a Trading Hour, or 2) the Trading Hour after the current trading hour that causes the residual energy, if RIE occurs at the end of a Trading Hour.
MSS Load Following Energy (MSS LFE)
IIE, exclusive of SRE, RED, and RIE, produced or consumed due to Load Following by an MSS. LFE is the IIE that corresponds to the algebraic Qualified Load Following Instruction (QLFI) relative to the DAS. LFE does not overlap with SRE, RED, or RIE, but it may overlap with DASE, Derate Energy, Exceptional Dispatch Energy, Real-Time Self-Scheduled Energy, and Optimal Energy. MSS LFE is paid/charged the Real-Time LMP as reflected in Section 11.5.1 of the CAISO Tariff and it is not included in BCR as reflected in Section 11.8.4 of the CAISO Tariff.
MSSLFE
Real-Time Pumping Energy (RTPE)
IIE from PSH or Pump Resources, exclusive of SRE, RED, consumed below the DAS when Dispatched in pumping mode, or produced from pumping operation due to Pumping Level reduction in real time, including pump shut-down. RTPE does not overlap with any other Expected Energy type. RTPE is calculated separately based on the FMS or the DOP and charged or paid the FMM or RTD LMP as reflected in Section 11.5.1 of the CAISO Tariff and it is included in BCR at the relevant pumping Cost as reflected in Section 11.8.4.1.4 of the CAISO Tariff.
RTPE
Real-Time Minimum Load
IIE, exclusive of SRE, RED, and RIE, produced due to the Minimum Load of a Generating Unit that is committed in the RUC or the RTM (i.e., without a Day-Ahead Schedule) or a Constrained Output Generator (COG) that is committed
MLE
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Expected Energy Category
Definition Published
Enumeration
Energy (RTMLE) in the IFM with a DAS below the registered Minimum Load (because COGs are modeled as flexible in the IFM). If the resource is committed in RTM for Load Following, RTMLE is accounted as MSSLFE instead. RTMLE is IIE above the Day-Ahead Schedule (or zero if there is no DAS) and below the registered Minimum Load. RTMLE does not overlap with any other Expected Energy type. RTMLE will be zero in the initial base model. RTMLE is calculated separately based on the FMS or the DOP and paid the FMM and RTD LMP as reflected in Section 11.5.1 of the CAISO Tariff and it is included in BCR at the relevant minimum load cost as reflected in Section 11.8.4.1.2 of the CAISO Tariff. IIE that is consumed when a resource that is scheduled in the DAM is shut down in the RTM is accounted as Optimal Energy and not as RTMLE.
Derate Energy (DRE) — also referred to as SLIC Energy
Extra-marginal IIE, exclusive of SRE, RED, RIE, LFE, and RTMLE, produced or consumed due to Minimum Load overrates or Maximum Capacity derates. DRE is produced above the higher of the DAS or the registered Minimum Load, and below the lower of the overrated Minimum Load and the DOP, or consumed below the lower of the DAS o and above the higher of the derated Maximum Capacity or the DOP. There could be two DRE slices, one for the Minimum Load overrate, and one for the Maximum Capacity derate. DRE does not overlap with SRE, RED, RIE, RTMLE, Exceptional Dispatch Energy, or Optimal Energy, but it may overlap with DASE and LFE. DRE is calculated separately based on the FMS or the DOP and paid/charged the FMM or RTD LMP as reflected in Section 11.5.1 of the CAISO Tariff and it is not included in BCR as reflected in Section 11.8.4 of the CAISO Tariff.
Ramping energy in the intervals before or after the minimum load re-rate can be classified as de-rate energy if the ramping is incurred due to the de-rate.
SE
Exceptional Dispatch Energy
Extra-marginal IIE, exclusive of SRE, RED, RIE, LFE, RTMLE, and DRE, produced or consumed due to manual (non-economic) Exceptional Dispatch
EDE
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Expected Energy Category
Definition Published
Enumeration
(EDE) Instructions that are binding in the relevant Dispatch Interval. Without MSS Load Following, EDE is produced above the LMP index and below the lower of the DOP or the Exceptional Dispatch instruction, or consumed below the LMP index and above the higher of the DOP or the Exceptional Dispatch Instruction. The LMP index is the capacity in the relevant Energy Bid that corresponds to a bid price equal to the relevant LMP. EDE does not overlap with SRE, RED, RIE, RTMLE, DRE, or Optimal Energy, but it may overlap with DASE and LFE. Exceptional Dispatch Energy is calculated separately based on the FMS or the DOP and paid/charged at a price that is specific to its type, either as-Bid or at the FMM or RTD LMP if there is no Bid as reflected in Section 11.5.6 of the CAISO Tariff, and it is not included in BCR as reflected in Section 11.8.4 of the CAISO Tariff..
Ramping energy in the intervals before or after the Exceptional Dispatch Instruction can be classified as Exceptional Dispatch Energy if the ramping is due to the Exceptional Dispatch.
Optimal Energy (OE) — also referred to as In- Sequence or Optimal Energy
Any remaining IIE after accounting for all other IIE subtypes constitutes OE. OE does not overlap with SRE, RED, RIE, RTMLE, DRE, and EDE, but it may overlap with DASE and LFE. OE is indexed against the relevant Energy Bid and sliced by service type, depending on the AS capacity allocation on the Energy Bid. OE is also divided into two parts: a) the part of OE that overlaps with MSS LFE (“Overlapping OE”), which is paid/charged the Real-Time LMP as reflected in Section 11.5.1, and it is not included in BCR since it is effectively cancelled by MSS LFE as reflected in Section 11.8.4 of the CAISO Tariff; and b) the remaining part (“Non-overlapping OE”), which is indexed against the relevant Energy Bid and sliced by Energy Bid price. The OE is calculated separately based on the FMS or the DOP. Non-overlapping OE slices are paid/charged the FMM or RTD LMP as reflected in Section 11.5.1 of the CAISO Tariff and they are included in BCR at the cost of the relevant Energy Bid prices as reflected in Section 11.8.4 of the CAISO Tariff. Any OE slice below or above the Energy Bid has no associated Energy Bid price and
OE
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Expected Energy Category
Definition Published
Enumeration
is settled as reflected in Section 11 of the CAISO Tariff and it is not included in BCR as reflected in Section 11of the CAISO Tariff.
RMR Energy (RMRE)
Total Expected Energy under RMR Dispatch. This energy is calculated irrelevant to other Expected Energy type and it may overlap with any other Expected Energy type. It is used for RMR contract based settlement as provided in Section 11 of the CAISO Tariff.
RMRE
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C.2 Expected Energy Calculation
The following section is meant to specify the formulas to calculate various Expected Energy amounts in a deterministic fashion.
All the following calculations take place for each Dispatch Interval (5-minute) in the target hour on resource level base.
Note: The following algorithm includes a generic set of formulas to calculate expected energy for non-generator resources
(NGR). This set of formulas reflects the ISO’s intent to implement future revisions to the base NGR model. The ISO is
publishing these formulas as part of the initial release of the base NGR model for administrative convenience and to provide
stakeholders with greater transparency regarding the ISO’s planned NGR model revisions. These formulas will allow the ISO
to reflect a non-zero value for an NGR’s minimum generation level and minimum load level. For purposes of the initial release
of the NGR base model, the minimum generation level and minimum load level will both equal zero. When interpreting the
algorithm for the NGR base model, the following conversion can be used for data mapping purpose,
SNGR Set of Non-Generating Resources; These are the Resources that market participants explicitly register to ISO’s Master File as NGR resources.
GMIN Registered Minimum Load at Generating Side of NGR resources. This is a zero or positive number. For the NGR base model, it is always zero and market participants can not register this value.
GMAX Registered Maximum Capacity at Generating Side of NGR resources. This is a positive number. For the NGR base model, market participants register this value to ISO’s Master File as Pmax of the NGR resource.
LMIN Registered Minimum Load at Load Side of NGR resources. This is a zero or negative number. For the NGR base model, it is always zero and market participants can not register this value.
LMAX
Registered Maximum Capacity at Load Side of NGR resources. This is a negative number. For the NGR base model, market participants register this value to ISO’s Master File as Pmin of the NGR resource.
GRTLOL Real-Time Lower Operating Limit at Gen Side; it reflects Minimum Load overrates at Gen Side. This function does not exist in the NGR base model. It is always zero in the NGR base model.
GRTUOL Real-Time Upper Operating Limit at Gen Side; it reflects Maximum Capacity derates at Gen Side. In the NGR base
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model, this value reflects the capacity impact to the Pmax when market participant submits an outage/de-rate to ISO’s SLIC application.
LRTLOL Real-Time Lower Operating Limit at Load Side; it reflects Minimum Load overrates at Load Side. This function does not exist in the NGR base model. It is always zero in the NGR base model.
LRTUOL Real-Time Upper Operating Limit at Load Side; it reflects Maximum Capacity derates at Load Side. In the NGR base model, this value reflects the capacity impact to the Pmin when market participant submits a re-rate to ISO’s SLIC application.
C.2.1.1 Top-level Algorithm
The following notation is used in the algorithm:
For…
If…
i Resource index.
.
h Trading Hour index in the target Trading Day.
N Number of Trading Hours in the target Trading Day.
k RTD Dispatch 5-minute interval index from the start of the Trading Hour.
f FMM Dispatch 15-minute interval index from the start of a Trading Hour.
j Exceptional Dispatch Instruction index.
l DOT sequence index from consecutive RTD, RTCD, or RTDD runs, as applicable.
P Resource power output.
t Time.
T Time limit.
m Market Type (DA, FMM, or RTD)
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Tl DOT timestamp for DOT sequence l. This is the mid-interval points (2.5 minutes middle point for 5-minute dispatch; 7.5 minutes middle point for 15-minute dispatch; or 5 minute middle point for 10-minute RTCD dispatch.
Th,k End time of Dispatch Interval k in Trading Hour h; Th,0 is the start of Trading Hour h.
T0 Shorthand notation for T1,0: the start of the target Trading Day.
TN Shorthand notation for TN,12: the end of the target Trading Day.
TFLOL Forward overrated lower operating limit extension time limit for Generating Resources. This applies to market type m = RTD, FMM.
TBLOL Backward overrated lower operating limit extension time limit for Generating Resources. This applies to market type m = RTD, FMM.
TFGLOL Forward overrated lower generating operating limit extension time limit for NGR. This applies to market type m = RTD, FMM.
TBGLOL Backward overrated lower generating operating limit extension time limit for NGR. This applies to market type m = RTD, FMM.
TFLLOL Forward overrated lower load operating limit extension time limit for NGR. This applies to market type m = RTD, FMM.
TBLLOL Backward overrated lower load operating limit extension time limit for NGR. This applies to market type m = RTD, FMM.
TFED Forward Exceptional Dispatch instruction extension time limit. This applies to market type m = RTD, FMM.
TBED Backward Exceptional Dispatch instruction extension time limit. This applies to market type m = RTD, FMM.
TFref Forward RIE terminating reference time.
TBref Backward RIE terminating reference time.
NULL No value.
SGEN Set of Generating Units.
STIE Set of Resource-Specific System Resources.
SIMP Set of Import System Resources; TIEIMP SS .
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SEXP Set of Export System Resources; TIEEXP SS .
SHPD Set of Non-Dynamic System Resources; TIEGENHPD SSS .
SRMR Set of RMR Resources; GENRMR SS
SPSH Set of Pumped-Storage Hydro (PSH) Resources; GENPSH SS
SPUMP Set of Pump (Participating Load) Resources; GENPUMP SS
SMSS Set of MSS Load Following Resources; IMPGENMSS SSS , HPDGENMSS SSS )( .
STG Set of Resource-Specific System Resources; GENTG SS .
SNGR Set of Non-Generating Resources; (Resources that are characterized by explicit identification of NGR resource)
SEIM Set of all EIM resources. These are resources which are located within an EIM Entity. TIEGENEIM SSS
SEIMP Set of EIM Participating Resources. EIMEIMP SS
SEIMNPR Set of EIM non-participating resources. These resources do not participate in the Real-Time Market.
EIMEIMNPR SS
GMIN Registered Minimum Load at Generating Side of NGR resources. This is a zero or positive number. It is assumed 0 for the NGR base model.
GMAX Registered Maximum Capacity at Generating Side of NGR resources. This is a positive number. It is assumed constant.
LMIN Registered Minimum Load at Load Side of NGR resources. This is a zero or negative number. It is assumed 0 for the NGR base model.
LMAX Registered Maximum Capacity at Load Side of NGR resources. This is a negative number. It is assumed constant.
PMIN Registered Minimum Load; it is assumed constant.
PMAX Registered Maximum Capacity; it is assumed constant.
PL Pumping Level for Pumped-Storage Hydro and Pump Resources. (5-minute for market type m = RTD or 15-minute
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for market type m = FMM).
DALEL Day-Ahead Lower Economic Limit; the bottom of the Day-Ahead mitigated Energy Bid.
DAUEL Day-Ahead Upper Economic Limit; the top of the Day-Ahead mitigated Energy Bid.
RTLOL Real-Time Lower Operating Limit; it reflects Minimum Load overrates. NGRSi
This applies to market type m =
RTD, FMM.
RTUOL Real-Time Upper Operating Limit; it reflects Maximum Capacity derates. NGRSi
This applies to market type m
= RTD, FMM.
GRTLOL Real-Time Lower Operating Limit at Gen Side; it reflects Gmin Load overrates at Gen Side. This applies to NGR
resources only, and it is assumed 0 for the NGR base model. NGRSi
This applies to market type m = RTD,
FMM.
GRTUOL Real-Time Upper Operating Limit at Gen Side; it reflects Gmax derates at Gen Side. This applies to NGR resources
only. NGRSi This applies to market type m = RTD, FMM.
LRTLOL Real-Time Lower Operating Limit at Load Side; it reflects Lmin overrates at Load Side. This applies to NGR
resources only, and it is assumed 0 for the NGR base model. NGRSi
This applies to market type m = RTD,
FMM.
LRTUOL Real-Time Upper Operating Limit at Load Side; it reflects Lmax derates at Load SIde. This applies to NGR
resources only. NGRSi This applies to market type m = RTD, FMM.
RTLEL Real-Time Lower Economic Limit; the bottom of the mitigated Real-Time Energy Bid.
RTUEL Real-Time Upper Economic Limit; the top of the mitigated Real-Time Energy Bid.
RTCS Real-Time Commitment Status (5-minute for market type m = RTD or 15-minute for market type m = FMM) (0: offline; 1: generating; –1: pumping; for Generating Units; 1: online for non-generator resources in both gen side or load side; 1 for all others).
RTBP(p) Real-Time mitigated Energy Bid function; bid price versus power output.
DAS Day-Ahead Schedule.
DASE Day-Ahead Scheduled Energy.
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DAMLE Day-Ahead Minimum Load Energy.
DAMLGE Day Ahead Minimum Load - Generation Energy; the Day-Ahead Energy attributed to Gmin for NGR
DAMLLE Day Ahead Minimum Load - Load Energy; the Day-Ahead Energy attributed to Lmin for NGR
DASSE Day-Ahead Self-Scheduled Energy.
DABAE Day-Ahead Bid Awarded Energy.
DAPE Day-Ahead Pumping Energy.
BASE Energy calculated for submitted Base Schedules. Applies to EIM resources.
FMS 15-minute Schedule of FMM market.
RFMS(t) Ramping Fifteen Minute Schedule (RFMS) is the continuous piecewise linear curve connecting consecutive FMS’s using their mid-interval points, from FMM runs.
RTBS Real-Time Base Schedule for ECA/ACA Resources. (5-minute for market type m = RTD or 15-minute for market type m = FMM). RTBS is assumed to be zero for all resources.
RTBD Real-Time Base Deviation. (5-minute for market type m = RTD or 15-minute for market type m = FMM). RTBD is assumed to be zero for all resources.
BSEIM Real-Time Base Schedule for EIM resources. Hourly value, submitted by resources within the EIM balancing authority area..
DOT Dispatch Operating Target.
DOP(t) Dispatch Operating Point function; expected resource power output versus time.
S(t) DOP Slope Direction function versus time for RTD market, or RFMS Slope Direction function versus time for FMM market.
SR(t) Standard Ramp function; expected resource scheduled power output, including the 20-min linear ramp across hourly boundaries, if applicable, versus time.
RTLMP Real-Time Locational Marginal Price (5-minute for market type m = RTD or 15-minute for market type m = FMM).
RTTGSS Real-Time Total Generating Self-Schedule for NGR
RTTLSS Real-Time Total Self-Schedule for NGR
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RTLED Real-Time Lower unconstrained Economic Dispatch based on the LMP and the Energy Bid. The LMP corresponds to 5-minute RTD LMP or 15-minute FMM LMP depending on market type m.
RTUED Real-Time Upper unconstrained Economic Dispatch based on the LMP and the Energy Bid. The LMP corresponds to 5-minute RTD LMP or 15-minute FMM LMP depending on market type m.
MDMIN Minimum EIM Manual Dispatch. This corresponds to market type m = RTD, FMM.
MDMAX Maximum EIM Manual Dispatch. This corresponds to market type m = RTD, FMM.
MDFIX Fixed EIM Manual Dispatch. This corresponds to market type m = RTD, FMM.
MDBND Binding EIM Manual Dispatch. This corresponds to market type m = RTD, FMM.
EDMIN Minimum Exceptional Dispatch. This corresponds to market type m = RTD, FMM.
EDMAX Maximum Exceptional Dispatch. This corresponds to market type m = RTD, FMM.
EDFIX Fixed Exceptional Dispatch. This corresponds to market type m = RTD, FMM.
EDBND Binding Exceptional Dispatch. This corresponds to market type m = RTD, FMM.
QLFI Qualified Load Following Instruction for non-HPD Load Following Resources, relative to Day-Ahead Schedule. (5-minute for market type m = RTD or 15-minute for market type m = FMM). 15-min FMM QLFI shall be the simple average of the relevant 5-minute RTD QLFI’s.
DASR Day-Ahead Reference Schedule.
FMSR 15-Minute Reference Schedule.
IIE Instructed Imbalance Energy. This applies to market type m = RTD, FMM
BED Base Energy Deviation. This applies to market type m = RTD, FMM. BED is assumed to be zero for all resources
SRE Standard Ramping Energy.
EXME Extra-Marginal Energy.
RED Ramping Energy Deviation. This applies to market type m = RTD, FMM. However, The total RED shall be settled as 5 minute RTD values.
ORED Overlapping Ramping Energy Deviation. This applies to market type m = RTD, FMM.
NRED Non-overlapping Ramping Energy Deviation. This applies to market type m = RTD, FMM.
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GNRED Non-Overlapping Ramping Energy Deviation for NGR in generating mode. This applies to market type m = RTD, FMM.
LNRED Non-Overlapping Ramping Energy Deviation for NGR in load mode. This applies to market type m = RTD, FMM.
RIE Residual Imbalance Energy. This applies to market type m = RTD, FMM. However, The total RIE shall be settled as 5 minute RTD values.
TRIE Top of the hour RIE. This applies to market type m = RTD, FMM.
GTRIE Top of the hour RIE for NGR in generating mode. This applies to market type m = RTD, FMM.
LTRIE Top of the hour RIE for NGR in load mode. This applies to market type m = RTD, FMM.
BRIE Bottom of the hour RIE. This applies to market type m = RTD, FMM.
GBRIE Bottom of the hour RIE for NGR in generating mode. This applies to market type m = RTD, FMM.
LBRIE Bottom of the hour RIE for NGR in load mode. This applies to market type m = RTD, FMM.
RTMLE Real-Time Minimum Load Energy. This applies to market type m = RTD, FMM.
RTMLGE Real Time Minimum Generating Energy; the Real-Time Energy attributed to Gmin for NGR. This applies to market type m = RTD, FMM.
RTMLLE Real Time Minimum Load Energy; the Real-Time Energy attributed to Lmin for NGR. This applies to market type m = RTD, FMM.
RTPE Real-Time Pumping Energy. This applies to market type m = RTD, FMM.
DRE Derate Energy. This applies to market type m = RTD, FMM.
UDRE Upper Derate Energy due to Pmax derates. This applies to market type m = RTD, FMM.
GUDRE Generating Upper Derate Energy due to Gmax derates. This applies to market type m = RTD, FMM.
LUDRE Load Upper Derate Energy due to Lmax derates. This applies to market type m = RTD, FMM.
LDRE Lower Derate Energy due to Pmin overrates. This applies to market type m = RTD, FMM.
GLDRE Generating Lower Derate due to Gmin overrates. This applies to market type m = RTD, FMM.
LLDRE Load Lower Derate Enegy due to Lmin overrates. This applies to market type m = RTD, FMM.
MSS MSS Load Following Energy. This applies to market type m = RTD, FMM. However, The total LFE shall be settled
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LFE as 5 minute RTD values.
MDE EIM Manual Dispatch Energy. This applies to market type m = RTD, FMM.
EDE Exceptional Dispatch Energy. This applies to market type m = RTD, FMM.
OE Optimal Energy. This applies to market type m = RTD, FMM.
OOE Overlapping Optimal Energy. This applies to market type m = RTD, FMM.
GOOE Overlapping Optimal Energy for NGR in generating mode. This applies to market type m = RTD, FMM.
LOOE Overlapping Optimal Energy for NGR in load mode. This applies to market type m = RTD, FMM.
NOE Non-overlapping Optimal Energy. This applies to market type m = RTD, FMM.
GNOE Non-Overlapping Optimal Energy for NGR in generating mode. This applies to market type m = RTD, FMM.
LNOE Non-Overlapping Optimal Energy for NGR in load mode. This applies to market type m = RTD, FMM.
TOL Configurable tolerance used in integral termination time calculation; set by default to 0.005 MW.
RAMPT Ramping Tolerance expected energy.
TEE Total Expected Energy (based on DOP).
TTEE Total Target Expected Energy (based on RDOT).
RDOT(t) Ramping Dispatch Operating Target; a continuous piecewise linear curve connecting consecutive DOTs using their mid-interval points, from RTD, RTCD, or RTDD runs, as applicable.
All capacity quantities are in MW, all energy quantities are in MWh, all prices are in $/MWh, and time is in sec.
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Expected Energy Calculation Algorithm
Any absent variables are considered zero. For example, a missing DAS is considered zero. Energy quantities are zero by
default when the relevant conditions in their formula do not hold. One exception to this rule, given an interval and a resource, if
the resource is not committed or within the Start Up/shutdown period in DA or RT, there should be no Expected Energy and
allocation calculated. This is to avoid a lot of zero Expected Energy being calculated. The following formula is assuming a
principle of “No DOP No Expected Energy”.
The Total Self-Schedule is the sum of all self-schedules except pumping self-schedules. The Energy Bid, and thus the
Lower/Upper Economic Limits are relative to the Total Self-Schedule. The Lower Economic Limit is equal to the higher of the
Total Self-Schedule or the Minimum Load. For NGRs, the Lower Economic Limit is equal to the bottom of the energy bid curve.
The Upper Economic Limit is equal to the top of the Energy Bid. If there is no Energy Bid, the Upper Economic Limit is equal to
the Lower Economic Limit.
The Lower Operating Limit is greater than or equal to the Minimum Load and it reflects Minimum Load overrates. The Minimum
Load and the Lower Operating Limit for System Resources are both zero. The Upper Operating Limit is less than or equal to
the Maximum Capacity and it reflects Maximum Capacity derates. The Maximum Capacity and the Upper Operating Limit for
System Resources are both infinite.
In MQS 2.0, the following assumptions are also made to a pump or pump storage resource in pumping mode:
1. There will be no operating mode switch between FMM and RTD. If a resource is committed in pumping mode in FMM, it
cannot change to any other mode except in the event of outage, which leads from pumping mode to offline;
2. For a resource in pumping, there is only one constant pumping level that this resource can operate on (constant
pumping level);
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3. When a resource is started up into pumping model or shut down from pumping mode, the ramping is assumed infinite.
A vertical line of DOP dispatch from zero to Pumping Level (startup) or vertical line of pumping level to zero (shutdown)
is assumed;
4. When a pump storage switch between pumping mode and generation mode in any given market, it is assumed that it
has to go through an offline period to meet the minimum down time requirement;
5. Schedules and DOPs in pumping mode are all negative MWs;
6. For all NGRs there will be an assumption that Gmin = Lmin = 0; The NGR base model will not accommodate any
resource where Gmin or Lmin is not 0.
Given those assumptions, the possible Expected Energy incurred by resources in pumping mode will be Standard Ramping
Energy, Ramping Energy Deviation, Day-Ahead Pumping Energy and Real-Time Pumping Energy.
TIE
khiMAXi
khiMINi
TGHPDTIEGENMAXikhikhiMINi
TGHPDTIEGENMAXihihiMINi
SiRTUOLP
RTLOLP
SSSSiPRTUOLRTLOLP
SSSSiPRTUELRTLELP
,,
,,
,,,,
,,
0
0
0
NGR
MINikhikhiMAXi
MAXikhikhiMINi
MAXihihiMAXi
Si
LLRTLOLLRTUOLL
GGRTUOLGRTLOLG
GRTUELRTLELL
,,,,
,,,,
,,
NGR
MINi
MINiSi
L
G
0
0
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NGR
khi
khiSi
LRTLOL
GRTLOL
0
0
,,
,,
C.2.1.1.1 Day-Ahead Scheduled Energy
NGRhihi SiDASDASE hr 1),0max( ,,
NGRhihi SiDASDASE hr 1,,
C.2.1.1.2 Day-Ahead Minimum Load Energy
NGRMINihihi SiPDASDAMLE hr 1,min,0max ,,
NGRhihihi SiDAMLLEDAMLGEDAMLE ,,,
NGRMINihihi SiGDASDAMLGE hr1,min,0max ,,
NGRMINihihi SiLDASDAMLLE hr1,max,0min ,,
Note: For NGR base model: Since MINiG =0, MINiL =0, this will result in hiDAMLE , =0.
C.2.1.1.3 Day-Ahead Self Scheduled Energy
NGRMINihihihi SiPDALELDASDASSE hr 1,min,0max ,,,
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Formatted: Font: 8 pt, Not Italic
NGR
hiMINihihi
hiMINihihi
hi SiDASLDAUELDAS
DASGDALELDASDASSE
0hr1,max,0min
0hr1,min,0max
,,,
,,,
,
C.2.1.1.4 Day-Ahead Bid Awarded Energy
NGRhihihi SiDALELDASDABAE hr1,0max ,,,
NGR
hihihi
hihihi
hi SiDASDAUELDAS
DASDALELDASDABAE
0hr1,0min,0min
0hr1,0max,0max
,,,
,,,
,
C.2.1.1.5 Day-Ahead Pumping Energy
NGRhihi SiDASDAPE hr 1,0min ,,
C.2.1.1.6 Block Energy Accounting Rules
The DOP of the following Resources is converted to a step function at the relevant DOTs for Expected Energy accounting as
follows:
)(12,,2,1,)( ,1,,,,, HPDTGTIEkhkhkhikhi SSSikTtTDOTtDOP
C.2.1.1.7 Instructed Imbalance Energy
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Formatted: Font: 8 pt, Not Italic
RTDmtdFMStDOP
IIE
FMMmtdDASFMS
IIE
kh
kh
fh
fh
T
T
fhihi
khmi
T
T
hifhi
fhmi
,
1,
,
1,
3600
)(
3600
,,,
,,,
,,,
,,,
For Generating Units, System Resources, and Non-Generator Resources, positive Instructed Imbalance Energy is produced,
whereas negative Instructed Imbalance Energy is consumed. The converse is true for Export System Resources, i.e., positive
Instructed Imbalance Energy is consumed, whereas negative Instructed Imbalance Energy is produced.
Instructed Imbalance Energy Calculations for the FMM and RTD are illustrated graphically in Figure 1Figure 1 below.
Figure 5a. Instructed imbalance Energy Stack – generation sideFigure 1a Instructed Imbalance Energy for a Generating Resource. RTD DOP is greater than FMM schedule, which is greater than DA schedule.
Figure 5a. Instructed imbalance Energy Stack – generation side. Figure 1Figure 1b Instructed Imbalance Energy for a Generating Resource. RTD DOP is less than FMM schedule and DA schedule, FMM is greater than DA schedule.
Figure 5a. Instructed imbalance Energy Stack – generation side. Figure 1Figure 1c Instructed Imbalance Energy for a Generating Resource. RTD DOP is greater than FMM schedule and DA schedule, FMM is less than DA schedule.
DOP
FMS
IIE15(+) IIE5(−)
DAS
DOP
FMS
IIE15(+)
IIE5(+)
DASE(+)
Formatted: Font: (Default) Arial, 11 pt
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Formatted: Font: 8 pt, Not Italic
C.2.1.1.8 Standard Ramping Energy
The Standard Ramp function is defined as follows:
TIEHPDhi
TIEHPD
hhh
hihi
hi
hhhi
hhh
hihi
hi
hi
SSiDAS
SSi
TtTTtDASDAS
DAS
TtTDAS
TtTtTDASDAS
DAS
tSR
,
12,10,10,
,1,
,
10,2,,
2,0,2,
,1,
,
,
)(1200
)(1200
)(
The Standard Ramping Energy is calculated as follows:
1232
1196
296
132
3600
)(
,1,
,1,
,1,
,1,
,,
,,
,
1,
kSSiDASDAS
kSSiDASDAS
kSSiDASDAS
kSSiDASDAS
tdDAStSR
SRE
TIEHPDhihi
TIEHPDhihi
TIEHPDhihi
TIEHPDhihi
T
T
hihi
khi
kh
kh
C.2.1.1.9 MSS Load Following Energy
The MSS Load Following Energy is calculated as follows:
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Formatted: Font: 8 pt, Not Italic
MSS
T
T
fhFMMikhmi
khmi
fhmi
T
T
hihifhmihi
fhmi
T
T
hihifhmihi
fhmi
Si
RTDmtdQLFIQLFI
LFE
FMMm
QLFItdtSRDASQLFIDAS
QLFItdtSRDASQLFIDAS
LFE
kh
kh
fh
fh
fh
fh
,
1,
,
1,
,
1,
3600
03600
)(,max,0max
03600
)(,min,0min
,,,,,,
,,,
,,,
,,,,,,
,,,
,,,,,,
,,,
MSSkhRTDifhFMMikhi SiLFELFELFE ,,,,,,,,
The total LFE shall be settled as 5 minute RTD values. Figure 1Figure 1 graphically illustrates the concept.
Formatted: Font: (Default) Arial, 11 pt
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Figure 2a Load Following Energy for a Generating Resource – Case A: QLFI5>QLFI115>0
DAS
DOP
FMS
OE15(+)
OE5(+)
DASE(+)
DASRR
FMSR
LFE15(+)
LFE5(+)
QLFI15(+)
(QLFI5−QLFI15)(+)
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Formatted: Font: 8 pt, Not Italic
Figure 2Figure 2b Load Following Energy for a Generating Resource – Case B: 0>QLFI5<QLFI115>0
DAS
DOP
FMS
OE15(+)
OE5(+)
DASE(+)
DASRR
FMSR
LFE15(+)
LFE5(−)
QLFI15(+)
(QLFI5−QLFI15)(−)
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Formatted: Font: 8 pt, Not Italic
Figure 2Figure 2c Load Following Energy for a Generating Resource – Case C: QLFI5<QLFI115<0
DAS
DOP
FMS
OE15(+)
OE5(+)
DASE(+) DASRR
FMSR
LFE15(−)
LFE5(−)
QLFI15(−)
(QLFI5−QLFI15)(−)
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Formatted: Font: 8 pt, Not Italic
Figure 2Figure 2d Load Following Energy for a Generating Resource – Case D: 0>QLFI5>QLFI115<0
DAS
DOP
FMS
OE15(+)
OE5(+)
DASE(+) DASRR
FMSR
LFE15(−)
LFE5(+)
QLFI15(−)
(QLFI5−QLFI15)(+)
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Formatted: Font: 8 pt, Not Italic
C.2.1.1.10 Reference Schedule
To combine the distinct effects of Load Following in the formulae, it is convenient to define the following Reference Schedule
function for DAS and FMS:
RTDmkTtTQLFIQLFIFMSFMSRtFMSR
FMMmfTtTQLFIDASDASRtDASR
khkhfhFMMikhmifhikhihi
fhfhfhmihifhihi
12,,2,1,)(
4,,2,1,)(
,1,,,,,,,,,,,,
,1,,,,,,,,
C.2.1.1.11 Real-Time Pumping Energy
RTPE is the algebraic sum of negative IIE due to pumping increase and positive IIE due to pumping reduction, as follows:
TIEGEN
T
T
fhihii
T
T
fhihii
khmi
T
T
hihihifhi
T
T
hihihifhi
fhmi
SSi
RTDm
tdFMStFMSRtDOP
tdFMStFMSRtDOP
RTPE
FMMm
tdtSRDAStDASRFMS
tdtSRDAStDASRFMS
RTPE
kh
kh
kh
kh
fh
fh
fh
fh
,
1,
,
1,
,
1,
,
1,
3600
),(max)(,0min,0max
3600
),(,0min)(,0min
3600
)(,),(max,0min,0max
3600
)(,),(,0min,0min
,,,
,,,
,,,
,,,,,
,,,,,
,,,
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Formatted: Font: 8 pt, Not Italic
NGRkhi SiRTPE 0,,
The concept of Real-Time Pumping Energy is illustrated graphically in Figure 3Figure 3.
FMS
RTPE15(+) DASE(−)
OE15(+) OE5(−)
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Formatted: Font: 8 pt, Not Italic
Figure 3a Real-Time Pumping Energy for a Pump Storage Hydro Resource. RTD in pump mode, FMM in generation mode, DA in pump mode.
DAS
DOP
RTPE5(−)
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Figure 3Figure 3b Real-Time Pumping Energy for a Pump Storage Hydro Resource. RTD in pump mode, FMM and DA in generation mode. FMM schedule is greater than DA schedule.
DAS
DOP
FMS
RTPE5(−)
DASE(+)
OE15(+) OE5(−)
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Formatted: Font: 8 pt, Not Italic
Figure 3Figure 3c Real-Time Pumping Energy for a Pump Storage Hydro Resource. RTD in pump mode, FMM and DA in generation mode. FMM schedule is greater than DA schedule.
DAS
DOP
FMS
RTPE5(−)
DASE(+)
OE15(−)
OE5(−)
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Formatted: Font: 8 pt, Not Italic
C.2.1.1.12 Real-Time Minimum Load Energy
TIEGENT
T
fhihiMINii
khmi
T
T
hihihiMINifhi
fhmi
SSi
RTDmtdFMStFMSRPtDOP
RTMLE
FMMmtdtSRDAStDASRPFMS
RTMLE
kh
kh
fh
fh
,
1,
,
1,
3600
),(,0max),(min,0max
3600
)(,),(,0max,min,0max
,,,
,,,
,,,,,
,,,
NGRkhikhikhi SiRTMLLERTMLGERTMLE ,,,,,,
NGRT
T
fhihiMINii
khmi
T
T
hihihiMINifhi
fhmi
Si
RTDmtdFMStFMSRGtDOP
RTMLGE
FMMmtdtSRDAStDASRGFMS
RTMLGE
kh
kh
fh
fh
,
1,
,
1,
3600
),(,0max),(min,0max
3600
)(,),(,0max,min,0max
,,,
,,,
,,,,,
,,,
NGRT
T
fhihiMINii
khmi
T
T
hihihiMINifhi
fhmi
Si
RTDmtdFMStFMSRLtDOP
RTMLLE
FMMmtdtSRDAStDASRLFMS
RTMLLE
kh
kh
fh
fh
,
1,
,
1,
3600
),(,0min),(max,0min
3600
)(,),(,0min,max,0min
,,,
,,,
,,,,,
,,,
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The concept of Real-Time Minimum Load Energy is illustrated graphically in Figure 4.
DOP
FMS
OE5(+)
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Formatted: Font: 8 pt, Not Italic
Figure 4a Real-Time Minimum Load Energy for a COG Generating Resource. RTD dispatch greater than FMM schedule, which is greater than Pmin. DA schedule less than Pmin. RTMLE is applicable to the FMS only.
DAS
RTMLE15(+)
DAMLE(+)
PMIN
OE15(+)
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Formatted: Font: 8 pt, Not Italic
Figure 4b Real-Time Minimum Load Energy for a COG Generating Resource. RTD dispatch above Pmin, FMM schedule is zero. DA schedule is below Pmin. RTMLE is applicable to the DOP.
DAS
DOP
FMS=0
(No FMS)
RTMLE5(+)
OE5(+)
DAMLE(+)
PMIN
OE15(−) OE5(+)
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Figure 4c Real-Time Minimum Load Energy for a Generating Resource. RTD dispatch above Pmin, FMM and DA schedules are zero. RTMLE is applicable to the DOP.
DAS=0
(No DAS)
DOP
FMS=0
(No FMS)
RTMLE5(+)
OE5(+)
PMIN
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Figure 4d Real-Time Minimum Load Energy for a Generating Resource. RTD dispatch and FMM schedule above Pmin, RTD dispatch is below FMM schedule. DA schedule is zero. RTMLE is applicable to the FMM schedule.
DOP
FMS
RTMLE15(+)
OE5(−)
PMIN
OE15(+)
DAS=0
(No DAS)
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Figure 4e Real-Time Minimum Load Energy for a Generating Resource. RTD dispatch above Pmin, FMM schedule is zero. DA schedule is above Pmin. Since the min load energy is covered by the DA schedule, there is no RTMLE.
DAS
DOP
FMS=0
(No FMS)
OE5(+) DASE(+)
PMIN
OE15(−)
DAMLE(+)
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Figure 4f Real-Time Minimum Load Energy for a Pump Storage Hydro Resource. RTD dispatch above Pmin, FMM schedule in pump mode. DA schedule is zero. RTMLE is applicable to the DOP.
DOP
FMS
RTMLE5(+)
PMIN
OE5(+)
DAS=0
(No DAS) RTPE15(−) RTPE5(+)
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Formatted: Font: 8 pt, Not Italic
C.2.1.1.13 Extra-Marginal Energy
Extra-Marginal Energy is either produced Instructed Imbalance Energy at a higher bid price than the Real-Time LMP or
consumed Instructed Imbalance Energy at a lower bid price than the Real-Time LMP, exclusive of Standard Ramping Energy.
For Generating Units in generating mode and Non-Generator resources and System Resources, Instructed Imbalance Energy
without a bid price, i.e., below or above the Energy Bid, is considered to be bid at – if it is lower than the Lower Economic
Limit, and at + if it is higher than the Upper Economic Limit. The converse is true for Export System Resources, i.e.,
Instructed Imbalance Energy is considered to be bid at + if it is lower than the Lower Economic Limit, and at – if it is higher
than the Upper Economic Limit. For Pumped-Storage Hydro and Pump Resources in pumping mode, Instructed Imbalance
Energy is considered to be bid at + if it is higher than the Pumping Level, and at – if it is lower than the Pumping Level.
To calculate Extra-Marginal Energy, the Real-Time LMP (5-minute for market type m = RTD or 15-minute for market type m =
FMM) must be indexed against the relevant Energy Bid as follows:
NGR
khmimikhmikhmi
khmi
khmihikhmi
khmihikhmi
fhmimikhmifhmi
fhmi
fhmihifhmi
fhmihifhmi
Si
RTDm
RTCSPLRTUEDRTLED
RTCSRTLMPpRTBPpRTUED
RTLMPpRTBPpRTLED
FMMm
RTCSPLRTUEDRTLED
RTCSRTLMPpRTBPpRTUED
RTLMPpRTBPpRTLED
1
0)(min
)(max
1
0)(min
)(max
,,,,,,,,,,
,,,
,,,,,,,
,,,,,,,
,,,,,,,,,,
,,,
,,,,,,,
,,,,,,,
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
khmihikhmi
khmihikhmi
fhmihifhmi
fhmihifhmi
Si
RTDmRTLMPpRTBPpRTUED
RTLMPpRTBPpRTLED
FMMmRTLMPpRTBPpRTUED
RTLMPpRTBPpRTLED
)(min
)(max
)(min
)(max
,,,,,,,
,,,,,,,
,,,,,,,
,,,,,,,
RTLED and RTUED are either both equal to the Energy Bid breakpoint where the bid price jumps over the RTLMP, including
the RTLEL or RTUEL, or equal to the start and end, respectively, of the Energy Bid segment with a bid price equal to the
RTLMP when the resource is marginal. RTLED and RTUED are both equal to the Pumping Level for pumping mode. Also it is
important to note that, when there is no Real-Time Energy Bid,
RTDmSSiPRTSSRTUEDRTLED
FMMmSSiPRTSSRTUEDRTLED
TIEGENMINihikhmikhmi
TIEGENMINihifhmifhmi
),max(
),max(
,,,,,,,
,,,,,,,
RTDmSi
RTTLSSRTTGSS
RTTLSSLRTTLSS
RTTGSSGRTTGSS
RTUEDRTLED
FMMmSi
RTTLSSRTTGSS
RTTLSSLRTTLSS
RTTGSSGRTTGSS
RTUEDRTLED
NGR
hihi
hiMINihi
hiMINihi
khmikhmi
NGR
hihi
hiMINihi
hiMINihi
fhmifhmi
00
0),min(
0),max(
{
00
0),min(
0),max(
,,
,,
,,
,,,,,,
,,
,,
,,
,,,,,,
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Formatted: Font: 8 pt, Not Italic
In general, RTLED and RTUED may differ in each Dispatch Interval. For the following sections, it is convenient to define the
following functions:
RTDmkTtTRTUEDtRTUED
RTLEDtRTLED
FMMmfTtTRTUEDtRTUED
RTLEDtRTLED
khkh
khmihmi
khmihmi
fhfh
fhmihmi
fhmihmi
12,,2,1,)(
)(
4,,2,1,)(
)(
,1,
,,,,,
,,,,,
,1,
,,,,,
,,,,,
Extra-Marginal Energy is calculated separately for each relevant Instructed Imbalance Energy subtype, as shown in the
following sections.
C.2.1.1.14 Binding Exceptional Dispatch
There could be multiple Exceptional Dispatch Instructions active in a given Dispatch Interval. Nevertheless, only one at most
can be binding, determined as follows:
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Formatted: Font: 8 pt, Not Italic
RTDm
NULL
RTLEDEDEDEDED
RTUEDEDEDEDED
ED
m
NULL
RTLEDEDEDEDED
RTUEDEDEDEDED
ED
khmijkhmMAXikhmFIXijkhmMAXikhmFIXi
khmijkhmMINikhmFIXijkhmMINikhmFIXi
khmBNDi
fhmijfhmMAXifhmFIXijfhmMAXifhmFIXi
fhmijfhmMINikfmFIXijfhmMINifhmFIXi
fhmBNDi
otherwise
,,min
,,max
FMM
otherwise
,,min
,,max
,,,,,,,,,,,,,,,,,
,,,,,,,,,,,,,,,,,
,,,
,,,,,,,,,,,,,,,,,
,,,,,,,,,,,,,,,,,
,,,
Considering any point in the unconstrained Economic Dispatch range as the Binding Exceptional Dispatch by default when one
does not exist, is an algorithmic mechanism to render it irrelevant in the equations without checking for its existence.
It is assumed that Exceptional Dispatch instructions cannot conflict; therefore, a Fixed Exceptional Dispatch cannot coexist with
other Fixed Exceptional Dispatches, a higher Min Exceptional Dispatch, or a lower Max Exceptional Dispatch; moreover, a Min
Exceptional Dispatch cannot be higher than a Max Exceptional Dispatch.
In general, the Binding Exceptional Dispatch may differ in each Dispatch Interval. For the following sections, it is convenient to
define the following function:
RTDmkTtTEDtED
mfTtTEDtED
khkhkhmBNDihmBNDi
fhfhfhmBNDihmBNDi
12,,2,1,)(
FMM 4,,2,1,)(
,1,,,,,,
,1,,,,,,
The binding Exceptional Dispatch Instruction in a given Dispatch Interval (5-minute for market type m = RTD or 15-minute for market type m = RTPD) is extended to subsequent and previous Dispatch Intervals without a binding Exceptional Dispatch Instruction while the Dispatch Operating Point ramps from/to the binding Exceptional Dispatch instruction to/from
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Formatted: Font: 8 pt, Not Italic
RTUED/RTLED for RTD market or FMS approaches the binding Exceptional Dispatch Instruction to/from RTUED/RTLED for RTPD market, as follows:
RTDmTFtTEDtED
mTFtTEDtED
EDkhkhmBNDihmBNDi
EDfhfhmBNDihmBNDi
)(
FMM )(
,,,,,,
,,,,,,
RTDmTBtTEDtED
mTBtTEDtED
EDkhkhmBNDihmBNDi
EDfhfhmBNDihmBNDi
)(
FMM )(
1,,,,,,
1,,,,,,
Where the forward and backward Exceptional Dispatch instruction extension time limits are calculated as follows:
RTDmTTtT
TOLtRTLEDtDOP
ts
NULLtED
T
TOLtRTUEDtDOP
ts
NULLtED
T
FMMmTTtT
TOLtRTLEDFMS
ts
NULLtED
T
TOLtRTUEDFMS
ts
NULLtED
T
TF
Nkh
hmii
mi
hmBNDi
hmii
mi
hmBNDi
Nfh
hmifhi
mi
hmBNDi
hmifhi
mi
hmBNDi
mED
)()(
1)(
)(
max,
)()(
1)(
)(
maxmax
)(
1)(
)(
max,
)(
1)(
)(
maxmax
,
,,
,
,,
,,
,
,,
,
,,,,
,
,,
,,,,
,
,,
,
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Formatted: Font: 8 pt, Not Italic
RTDmTTtT
TOLtRTLEDtDOP
ts
NULLtED
T
TOLtRTUEDtDOP
ts
NULLtED
T
mTTtT
TOLtRTLEDFMS
ts
NULLtED
T
TOLtRTUEDFMS
ts
NULLtED
T
TB
kh
hmii
i
hmBNDi
hmii
mi
hmBNDi
fh
hmifhi
mi
hmBNDi
hmifhi
mi
hmBNDi
mED
)()(
1)(
)(
min,
)()(
1)(
)(
minmin
FMM
)(
1)(
)(
min,
)(
1)(
)(
minmin
01,
,,
,,
,,
,
,,
01,
,,,,
,
,,
,,,,
,
,,
,
If the search reaches the end or start of the target Trading Day, it shall continue into subsequent or previous Trading Days as needed.
To complete the Exceptional Dispatch function, any remaining NULL sections are replaced after extensions as follows:
} , { )(2
)()()( ,,
,,,,
,, RTDRTPDmNULLtEDtRTUEDtRTLED
tED hmBNDi
hmihmi
hmBNDi
Considering any point in the
unconstrained economic dispatch range as the binding Exceptional Dispatch by default when one does not exist, is an algorithmic mechanism to render it irrelevant in the equations without checking for its existence.
C.2.1.1.15 Operating Limits
For the following sections, it is convenient to define the following operating limit functions:
CAISO Business Practice Manual BPM for Market Operations
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
RTDmSSikTtTRTLOLtRTLOL
RTUOLtRTUOL
FMMmSSifTtTRTLOLtRTLOL
RTUOLtRTUOL
TIEGENkhkh
khmihmi
khmihmi
TIEGENfhfh
fhmihmi
fhmihmi
,12,,2,1,)(
)(
,4,,2,1,)(
)(
,1,
,,,,,
,,,,,
,1,
,,,,,
,,,,,
RTDmSikTtTGRTLOLtGRTLOL
GRTUOLtGRTUOL
FMMmSifTtTGRTLOLtGRTLOL
GRTUOLtGRTUOL
NGRkhkh
khmihmi
khmihmi
NGRfhfh
fhmihmi
fhmihmi
,12,,2,1,)(
)(
,4,,2,1,)(
)(
,1,
,,,,,
,,,,,
,1,
,,,,,
,,,,,
RTDmSikTtTLRTLOLtLRTLOL
LRTUOLtLRTUOL
FMMmSifTtTLRTLOLtLRTLOL
LRTUOLtLRTUOL
NGRkhkh
khmihmi
khmihmi
NGRfhfh
fhmihmi
fhmihmi
,12,,2,1,)(
)(
,4,,2,1,)(
)(
,1,
,,,,,
,,,,,
,1,
,,,,,
,,,,,
An overrated operating limit in a given Dispatch Interval is extended to subsequent and previous Dispatch Intervals while the Dispatch Operating Point ramps from/to that overrated operating limit to/from RTUED/RTLED, as follows:
RTDmTFtTRTLOLtRTLOL
FMMmTFtTRTLOLtRTLOL
mLOLkhkhmihmi
mLOLfhfhmihmi
,,,,,,,
,,,,,,,
)(
)(
CAISO Business Practice Manual BPM for Market Operations
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
RTDmTBtTRTLOLtRTLOL
FMMmTBtTRTLOLtRTLOL
mLOLkhkhmihmi
mLOLfhfhmihmi
,1,,,,,,
,1,,,,,,
)(
)(
RTDmTFtTGRTLOLtGRTLOL
FMMmTFtTGRTLOLtGRTLOL
mGLOLkhkhmihmi
mGLOLfhfhmihmi
,,,,,,,
,,,,,,,
)(
)(
RTDmTBtTGRTLOLtGRTLOL
FMMmTBtTGRTLOLtGRTLOL
mGLOLkhkhmihmi
mGLOLfhfhmihmi
,1,,,,,,
,1,,,,,,
)(
)(
RTDmTFtTLRTLOLtLRTLOL
FMMmTFtTLRTLOLtLRTLOL
mLLOLkhkhmihmi
mLLOLfhfhmihmi
,,,,,,,
,,,,,,,
)(
)(
RTDmTBtTLRTLOLtLRTLOL
FMMmTBtTLRTLOLtLRTLOL
mLLOLkhkhmihmi
mLLOLfhfhmihmi
,1,,,,,,
,1,,,,,,
)(
)(
Where the forward and backward overrated lower operating limit extension time limits are calculated as follows:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-49
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
RTDmTTtT
TOLtRTUEDtDOP
ts
PRTLOL
T
mTTtT
TOLtRTUEDFMS
ts
PRTLOL
T
TF
Nkh
hmii
mi
MINikhmi
Nfh
hmifhi
mi
MINifhmi
mLOL
)()(
1)(max
FMM
)(
1)(max
,
,,
,
,,,
,
,,,,
,
,,,
,
RTDmTTtT
TOLtRTUEDtDOP
ts
PRTLOL
T
mTTtT
TOLtRTUEDFMS
ts
PRTLOL
T
TB
kh
hmii
mi
MINikhmi
fh
hmifhi
mi
MINifhmi
mLOL
)()(
1)(min
FMM
)(
1)(min
01,
,,
,
,,,
01,
,,,,
,
,,,
,
RTDmTTtT
TOLtRTUEDtDOP
ts
GGRTLOL
T
mTTtT
TOLtRTUEDFMS
ts
GGRTLOL
T
TF
Nkh
hmii
mi
MINikhmi
Nfh
hmifhi
mi
MINifhmi
mGLOL
)()(
1)(max
FMM
)(
1)(max
,
,,
,
,,,
,
,,,,
,
,,,
,
CAISO Business Practice Manual BPM for Market Operations
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
RTDmTTtT
TOLtRTUEDtDOP
ts
GGRTLOL
T
mTTtT
TOLtRTUEDFMS
ts
GGRTLOL
T
TB
kh
hmii
mi
MINikhmi
fh
hmifhi
mi
MINifhmi
mGLOL
)()(
1)(min
FMM
)(
1)(min
01,
,,
,
,,,
01,
,,,,
,
,,,
,
RTDmTTtT
TOLtRTLEDtDOP
ts
LLRTLOL
T
mTTtT
TOLtRTLEDFMS
ts
LLRTLOL
T
TF
Nkh
hmii
mi
MINikhmi
Nfh
hmifhi
mi
MINifhmi
mLLOL
)()(
1)(max
FMM
)(
1)(max
,
,,
,
,,,
,
,,,,
,
,,,
,
RTDmTTtT
TOLtRTLEDtDOP
ts
LLRTLOL
T
mTTtT
TOLtRTLEDFMS
ts
LLRTLOL
T
TB
kh
hmii
mi
MINikhmi
fh
hmifhi
mi
MINifhmi
mLLOL
)()(
1)(min
FMM
)(
1)(min
01,
,,
,
,,,
01,
,,,,
,
,,,
,
If the search reaches the end or start of the target Trading Day, it shall continue into subsequent or previous Trading Days as needed.
CAISO Business Practice Manual BPM for Market Operations
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
C.2.1.1.16 Slope Direction
For the RTD market, the Slope Direction of the Dispatch Operating Point function is the sign of its first derivative as follows:
RTDmtd
tDOPdtsm
increasing1
flat0
decreasing1)(
signum)(
For the RTD market, the Dispatch Operating Point may be discontinuous at the midpoint of each Dispatch Interval because of
“vertical” corrections due to the “projected” State Estimator solution. The Slope Direction may change at these points, however,
it remains constant for the first half and the second half of the Dispatch Interval. Note that the slope itself may change within
these halves because of ramp rate changes; however, the slope direction does not change. Therefore, the Dispatch Operating
Point Slope Direction can also be determined as follows:
CAISO Business Practice Manual BPM for Market Operations
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
RTDm
TtTT
TDOPTT
DOP
TDOPTT
DOP
TDOPTT
DOP
TTtT
TTDOPTDOP
TTDOPTDOP
TTDOPTDOP
ts
kh
khkh
khi
khkh
i
khi
khkh
i
khi
khkh
i
khkh
kh
khkh
ikhi
khkh
ikhi
khkh
ikhi
khmi
,
,1,
,
,1,
,
,1,
,
,1,
,1,
1,
,1,
1,
,1,
1,
,1,
1,
,,,
2
)(2
1
)(2
0
)(2
1
2
2)(1
2)(0
2)(1
)(
For the FMM, a Ramping Fifteen Minute Schedule (RFMS) is defined as the continuous piecewise linear curve connecting consecutive FMS’s using their mid-interval points, i.e. dispatch results from FMM runs. The Slope Direction of the Ramping Fifteen Minute Schedule (RFMS) function is the sign of its first derivative as follows:
FMMmtd
tdRFMStsm
increasing1
flat0
decreasing1)(
signum)(
For the FMM, the Ramping Fifteen Minute Schedule (RFMS) may change at the midpoint of each 15-minute Dispatch Interval because of FMS change direction. The Slope Direction may change at these points, however, it remains constant for the first half and the second half of the 15-minute Dispatch Interval. The Dispatch Operating Point Slope Direction can also be determined as follows:
CAISO Business Practice Manual BPM for Market Operations
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
FMMm
TtTT
TFMSTFMS
TFMSTFMS
TFMSTFMS
TTtT
TFMSTFMS
TFMSTFMS
TFMSTFMS
ts
fh
fhfh
fhifhi
fhifhi
fhifhi
fhfh
fh
fhifhi
fhifhi
fhifhi
fhmi
,
,1,
1,,
1,,
1,,
,1,
1,
,1,
,1,
,1,
,,,
2)()(1
)()(0
)()(1
2)()(1
)()(0
)()(1
)(
C.2.1.1.17 Instructed Imbalance Energy Stack
Figure 5Figure 5 illustrates how the various Instructed Imbalance Energy subtypes stack. Formatted: Font: (Default) Arial, 11 pt
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-54
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5a. Instructed imbalance Energy Stack – generation side
NGRGENSSi
45' 50' 55' 0' 5' 10' 15'
MW
DAS
SRE
RED15
RΙE5
ΟE5
LDRE5
EDE5
OE5
LFE15
50' 55' 0' 5' 10' 15'
MW
DASR
RTUED5
ED5
RTLOL5
DASE
RED15
ΟE15
DASE
RΙE5
SRE
LFE15
OE15
EDE15
UDRE15 RTUOL1
5
RTLED1
5
DASR
DAS
DOP(t)
DOP(t)
SR(t)
SR(t)
T65
T25
T55
T15
RTLED5
ED5
RTUOL5
OE5
EDE5
UDRE5
ΟE5
FMS
ΟE15
FMS
RTUED1
5
ED15
RTLOL15
LDRE15
EDE15
OE15
FMS
FMS
RED5
RED5
FMSR LFE5
FMSR LFE5
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-55
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5b Instructed Imbalance Energy Stack for Incremental Residual Energy for a Generating Resource.
NGRGENSSi
DAS
Top Hour
Bottom Hour
RTUED5
Hour : (h+1) Hour : (h-1) Current Hour (h)
DOP
TBref TFref
RIE5 RIE5
Reference Interval
15 min
Reference Interval
15 min
T65 T85
Th,0 Th+1,0
FMS
RTUED15
T615 T815
RIE15 RIE15
DASE
OE15 OE15 OE15
OE5 OE5
OE5
DASE DASE
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-56
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5c Instructed Imbalance Energy Stack for Decremental Residual Energy for a Generating Resource
NGRGENSSi
DAS
Top Hour
Bottom Hour
Hour : (h+1) Hour : (h-1) Current Hour (h)
DOP
TBref TFref
Reference Interval
15 min
Reference Interval
15 min
T55
Th,0 Th+1,0
FMS RTLED15
T515 T715
RIE15 RIE15
DASE
OE15 OE15
OE15
OE5 OE5
OE5
RTLED5
RIE5 RIE5
DASE DASE
T715
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-57
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5d Instructed Imbalance Energy Stack for Incremental Residual Energy for a Generating Resource (RIE Overlapping Case)
NGRGENSSi
DAS
Top Hour
Bottom Hour
RTUED5
Hour : (h+1) Hour : (h-1) Current Hour (h)
DOP
TBref TFref
RIE5 RIE5
Reference Interval
15 min
Reference Interval
15 min
Th,0 Th+1,0
FMS
RTUED15
RIE15 RIE15
DASE
OE15 OE15 OE15
OE5 OE5
OE5
DASE DASE
T85 T65
T615 T815
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-58
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5e Instructed Imbalance Energy Stack for Decremental Residual Energy for a Generating Resource (RIE Overlapping Case)
NGRGENSSi
DAS
Top Hour
Bottom Hour
Hour : (h+1) Hour : (h-1) Current Hour (h)
DOP
TBref TFref
Reference Interval
15 min
Reference Interval
15 min
Th,0 Th+1,0
FMS RTLED15
T515 T715
RIE15 RIE15
DASE
OE15 OE15
OE15
OE5 OE5
OE5
RTLED5
RIE5 RIE5
DASE DASE
T715 T55
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-59
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-60
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5f Instructed Imbalance Energy Stack for a NGR. Generation side, RTD dispatch greater than DA schedule.
NGRSi
RΙE5
DOP(t)
SR(t)
50' 55' 0' 5' 10'
MW
DAS
SRE
RED15
RΙE5
LDRE15
EDE15
OE15
LFE15 DASR
RTUED15
ED15
GRTLOL15
DASE
DOP(t)
SR(t)
DASE SRE
50' 55' 0' 5' 10'
DASE
T65 T85
T25 T45
FMS FMS ΟE5
ΟE5
ΟE15 ΟE15
RED5 RED5
FMS
RED15
GRTLOL5
ED5
RTUED5
FMSR
LDRE5
EDE5
OE5
LFE5
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-61
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5g Instructed Imbalance Energy Stack for a NGR. Generation side, RTD dispatch less than DA schedule.
NGRSi
ED15
DASR
DAS
50’ 55’ 0’ 5’ 10’
RED15
DASE
RIE5
SRE
LFE15
OE15
EDE15
UDRE15
DOP(t)
SR(t)
50' 55’ 0’ 5’ 10'
RED15
DASE
RIE5
SRE
LFE15
OE15
EDE15
UDRE15
DOP(t)
SR(t)
DAS
DASRR
RTLED15
GRTUOL15
DASE
T35
T75 T55
T15
OE15
FMS FMS
RED5 RED5
ΟE5
FMSR
ED5
FMSR
RTLED5
ED5
GRTUOL5
LFE5
OE5
EDE5
UDRE5
LFE5
OE5
EDE5
UDRE5
RTLED15
GRTUOL15
RTLED5
GRTUOL5
ED15
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-62
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5h Instructed Imbalance Energy Stack for a NGR. Load side, RTD dispatch greater than DA schedule.
NGRSi
RΙE5
DOP(t)
SR(t)
50' 55' 0' 5' 10'
MW
DAS
SRE
RED15
RΙE5
UDRE15
EDE15
OE15
LFE15 DASR
RTUED15
ED15
LRTUOL15
DOP(t)
SR(t)
SRE
50' 55' 0' 5' 10'
DASE
T65 T85
T25 T45
FMS FMS ΟE5
ΟE5
ΟE15 ΟE15
RED5 RED5
FMS
RED15
LRTUOL5
ED5
RTUED5
FMSR
UDRE5
EDE5
OE5
LFE5
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-63
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5i Instructed Imbalance Energy Stack for a NGR. Load side, RTD dispatch less than DA schedule.
NGRSi
DAS
50'
DASE
LFE15
OE15
EDE15
DOP(t)
FMS FMS
RED5 RED5
ΟE5
FMSR
ED5
FMSR
RTLED5
ED5
LRTLOL5
LFE5
OE5
EDE5
LDRE5
LFE5
OE5
EDE5
LDRE15
RTLED15
LRTLOL15
RTLED5
LRTLOL5
55' 0' 5' 10' 50' 55' 0' 5' 10'
ΟE15
RTLED15
DAS
LRTLOL15
DASR DASR
ED15 ED15
LFE15
OE15
EDE15
LDRE5
LDRE15
SRE SRE
RΙE5 RΙE5
RED15 RED15
SR(t) SR(t)
DOP(t)
T15
T55
T35
T75
MW
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-64
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5j. Instructed Imbalance Energy Stack for a NGR. RTD dispatch on generation side dipping to load side, DA schedule on load side.
NGRSi
RΙE5
DOP(t)
ΟE5
SR(t)
50' 55' 0' 5' 10'
MW
DAS
RED15
RED15
RΙE5
ΟE5
DASR5
RTUED5
ED5
LRTUOL5
DASE
DOP(t)
SR(t)
DASE
RED15
50' 55' 0' 5' 10'
DASE
T65 T85
T25 T45
GRTLOL5
GMIN LDRE5
RTMGE5
RED5 RED15 RED5
RED5 RED5
FMS
LDRE5
RTMGE5
UDRE5
EDE5
OE5
LFE5
FMS FMS
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-65
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5k Instructed Imbalance Energy Stack for a NGR. RTD dispatch mainly on load side with some on generation side, DA schedule on generation side.
NGRSi
ED5
RTLED5
DASR
DAS
50' 55' 0' 5' 10'
RS
RTUED
ED
GRTLOL
RED15
RΙE5
RED15
LFE5
OE5
EDE5
UDRE5
DOP(t)
SR(t)
50' 55' 0' 5' 10'
MW
RED15
RΙE5
RED15
LFE5
OE5
EDE5
UDRE5
DOP(t)
SR(t)
DAS
DASR
RTLED5
ED5
GRTUOL5 DASE DASE
DASE
T35
T75 T55
T15
DAS
ΟE5
LDRE5
RTMLE5
LRTLOL5 RED5 RED5
RED5 RED5
FMS FMS
FMS
LMIN
DAS
RTMLE5
LDRE5 LRTLOL5
GRTUOL5
LMIN
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-66
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5l Instructed Imbalance Energy Stack for a NGR. Similar to item j above, but RTD dispatch stays on generation side.
NGRSi
RΙE5
DOP(t)
ΟE5
SR(t)
50' 55' 0' 5' 10'
MW
DAS
RED15
RΙE5
ΟE5
DASR
RTUED5
ED5
GRTLOL5
DASE
DOP(t) SR(t)
DASE
50' 55' 0' 5' 10'
T65
T25 T45
T85
RED5 RED5
FMS
FMS
RED15
RED15
LDRE5
EDE5
OE5
LFE5
RED15
FMS
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-67
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5m Instructed Imbalance Energy Stack for a NGR. Similar to item k above, but RTD dispatch stays on load side.
NGRSi
LRTLOL5
RTLED5
DASR
DAS
50' 55' 0' 5' 10'
RS
RTUED
ED
GRTLOL
RED15
RΙE5
DOP(t)
SR(t)
50' 55' 0' 5' 10'
MW
RED15
RΙE5
DOP(t)
SR(t)
DAS
DASR
RTLED5
ED5
LRTLOL5
DASE
ΟE5
T35
T75 T55
T15
DAS
RED5 RED5
FMS FMS
FMS
LFE5
RED15 RED15 OE5
EDE5
LDRE5
LFE5
OE5
EDE5
LDRE5 ED5
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-68
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5n. Instructed Imbalance Energy Stack for Generating Resource. Special OE Case. RTD dispatch greater than DA schedule.
NGRGENSSi
RΙE5
DOP(t)
SR(t)
50' 55' 0' 5' 10'
MW
DAS
SRE
RED15
RΙE5
LDRE15
EDE15
OE15
LFE15 DASR
RTUED15
ED15
RTLOL15
DASE
DOP(t)
SR(t)
DASE SRE
50' 55' 0' 5' 10'
DASE
T65 T85
T25 T45
FMS FMS ΟE5
ΟE5
ΟE15 ΟE15
RED5 RED5
FMS
RED15
RTLOL5 ED5
RTUED5
FMSR
LDRE5
EDE5
OE5
LFE5 OE15
OE5
RED15 RED15
T215 T415
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-69
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5o Instructed Imbalance Energy Stack for Generating Resource. Special OE Case. RTD dispatch less than DA schedule.
NGRGENSSi
DAS
50'
DASE
LFE15
OE15
EDE15
DOP(t)
FMS FMS
RED5 RED5
ΟE5
FMSR
ED5
FMSR RTLED5
ED5 RTUOL5
LFE5 OE5 EDE5
UDRE5
LFE5 OE5
EDE5
UDRE15
RTLED15
RTUOL15
RTLED5
RTUOL5
55' 0' 5' 10' 50' 55' 0' 5' 10'
ΟE15
RTLED15
DAS
RTUOL15
DASR DASR
ED15 ED15
LFE15
OE15
EDE15
UDRE5
UDRE15
SRE SRE
RΙE5 RΙE5
RED15 RED15
SR(t) SR(t)
DOP(t)
T15
T55 T35
T75
MW
OE5 OE5
OE15 OE15
DASE
RED15 RED15
T315 T115
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-70
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5p Instructed Imbalance Energy Stack for Generating Resource. Special RED Case. RTD dispatch greater than DA schedule.
NGRGENSSi
RΙE5
DOP(t)
SR(t)
50' 55' 0' 5' 10'
MW
DAS
SRE
RED15
RΙE5
LDRE15
EDE15
OE15
LFE15 DASR
RTUED15
ED15
RTLOL15
DASE
DOP(t)
SR(t)
DASE SRE
50' 55' 0' 5' 10'
DASE
T65 T85
T25 T45 FMS
ΟE5 ΟE5
RED5 RED5
FMS RED15
RTLOL5 ED5
RTUED5
FMSR
LDRE5
EDE5
OE5
LFE5 RED15 RED15
OE5 OE5
T215 T415
ΟE15, ΟE5 ΟE15, ΟE5
15' 45'
FMS
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-71
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5q Instructed Imbalance Energy Stack for Generating Resource. Special RED Case. RTD dispatch less than DA schedule.
NGRGENSSi
DAS
50'
DASE
LFE15
OE15
EDE15
DOP(t)
FMS FMS
RED5 RED5
ΟE5
FMSR
ED5
FMSR RTLED5
ED5 RTUOL5
LFE5 OE5 EDE5
UDRE5
LFE5 OE5
EDE5
UDRE15
RTLED15
RTUOL15
RTLED5
RTUOL5
55' 0' 5' 10' 50' 55' 0' 5' 10'
RTLED15
DAS
RTUOL15
DASR DASR
ED15 ED15
LFE15
OE15
EDE15
UDRE5
UDRE15
SRE SRE
RΙE5 RΙE5
RED15 RED15
SR(t) SR(t)
DOP(t)
T15
T55
T35
T75
MW
RED15 RED15
DASE
OE5 OE5 ΟE15, ΟE5
T115 T315
15' 45'
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-72
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5r Instructed Imbalance Energy Stack for Generating Resource. Special DRE & EDE Case. At various
intervals RTD dispatch is either greater than or less than DA schedule. NGRGEN
SSi
RΙE5
DOP(t)
SR(t)
MW
DAS
SRE
RED15
RΙE5
LDRE15
EDE15
OE15
LFE15 DASR
RTUED15
ED15
RTLOL15
DASE
DOP(t)
SR(t)
DASE SRE
T65 T85
T25 T45
FMS FMS ΟE5
ΟE5
ΟE15 ΟE15
RED5 RED5
FMS
RED15
RTLOL5
ED5
RTUED5
FMSR
LFE5
ΟE5
LFE5
LDRE15
EDE15
OE15
LFE15
ΟE
5
ΟE
5
ΟE
5
10' 5' 0' 55' 50' 10' 5' 0' 55' 50'
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-73
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5s Instructed Imbalance Energy Stack for Generating Resource. Special DRE & EDE Case. At various intervals
RTD dispatch is either less than or greater than DA schedule. NGRGENSSi
DAS
50'
DASE
LFE15
OE15
EDE15
DOP(t)
FMS FMS
RED5 RED5
ΟE5
FMSR
ED5
FMSR
RTLED5
ED5
RTUOL5
LFE5 LFE5
UDRE15
RTLED15
RTUOL15
55' 0' 5' 10' 50' 55' 0' 5' 10'
ΟE15
RTLED15
DAS
RTUOL15
DASR DASR
ED15 ED15
LFE15
OE15
EDE15
UDRE15
SRE SRE
RΙE5 RΙE5
RED15 RED15
SR(t) SR(t)
DOP(t)
T15
T55
T35
T75
DASE
RTLED5
ΟE5
ΟE
5
RTUOL5 ΟE5
ΟE
5 ΟE
5
ΟE
5
MW
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-74
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
C.2.1.1.18 Ramping Energy Deviation
The Ramping Energy Deviation is the sum of the Overlapping Ramping Energy Deviation that overlaps (and cancels) with
Standard Ramping Energy and the Non-overlapping Ramping Energy Deviation:
GEN
khmikhmikhmi
fhmifhmifhmi
Si
RTDmNREDOREDRED
mNREDOREDRED
FMM
,,,,,,,,,
,,,,,,,,,
GENkhRTDifhFMMikhi SiREDREDRED ,,,,,,,,
NGR
khmikhmikhmikhmi
fhmifhmifhmifhmi
Si
RTDmLNREDGNREDOREDRED
mLNREDGNREDOREDRED
FMM
,,,,,,,,,,,,
,,,,,,,,,,,,
NGRkhRTDifhFMMikhi SiREDREDRED ,,,,,,,,
The total RED shall be settled as 5 minute RTD values.
The Overlapping Ramping Energy Deviation is calculated as follows:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-75
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
ECATIEHPD
khmi
hihi
T
T
hihifhi
hihi
T
T
hihifhi
fhmi
SSSi
RTDmkORED
mf
DAStSRtdtSRDASFMS
DAStSRtdtSRDASFMS
OREDfh
fh
fh
fh
12,11,2,10
FMM 4,3,2,1
)(3600
)(,min,0max
)(3600
)(,max,0min
,,,
,,
,,,,
,,
,,,,
,,, ,
1,
,
1,
The Non-overlapping Ramping Energy Deviation may occur at the start and/or end of the Trading Hour, and only for as long as
the Dispatch Operating Point Slope Direction remains increasing or decreasing, as the relevant case may be. The Non-
overlapping Ramping Energy Deviation can be determined by searching forward from the start of the Trading Hour and
backward from the end of the Trading Hour as follows:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-76
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
ECATIEHPDNGR
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hmi
SSSSim
DASDAStdtSRtDASRtRTUEDtEDtRTLOLDAStFMS
DASDAStdtSRtDASRtRTLEDtEDtRTUOLDAStFMS
DASDAStdtSRtDASRtRTUEDtEDtRTLOLDAStFMS
DASDAStdtSRtDASRtRTLEDtEDtRTUOLDAStFMS
NRED
h
m
h
m
m
h
m
h
,FMM
3600
)(),(),(),(),(max),(min,0max
3600
)(),(),(),(),(min),(max,0min
3600
)(),(),(),(),(max),(min,0max
3600
)(),(),(),(),(min),(max,0min
,1,
4
,,,,,,,,1,,
,1,
3
,,,,,,,,1,,
,1,
2
,,,,,,,,1,,
,1,
1
,,,,,,,,1,,
,,
0,1
0,1
0,
0,
ECATIEHPDNGR
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hmi
SSSSiRTDm
DASDAStdtFMStFMSRtRTUEDtEDtRTLOLDAStDOP
DASDAStdtFMStFMSRtRTLEDtEDtRTUOLDAStDOP
DASDAStdtFMStFMSRtRTUEDtEDtRTLOLDAStDOP
DASDAStdtFMStFMSRtRTLEDtEDtRTUOLDAStDOP
NRED
h
m
h
m
m
h
m
h
,
3600
)(),(),(),(),(max),(min,0max
3600
)(),(),(),(),(min),(max,0min
3600
)(),(),(),(),(max),(min,0max
3600
)(),(),(),(),(min),(max,0min
,1,
4
,,,,,,,,1,
,1,
3
,,,,,,,,1,
,1,
2
,,,,,,,,1,
,1,
1
,,,,,,,,1,
,,
0,1
0,1
0,
0,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-77
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hmi
Sim
DASDAStdtSRtDASRtRTUEDtEDtGRTLOLDAStFMS
DASDAStdtSRtDASRtRTLEDtEDtGRTUOLDAStFMS
DASDAStdtSRtDASRtRTUEDtEDtGRTLOLDAStFMS
DASDAStdtSRtDASRtRTLEDtEDtGRTUOLDAStFMS
GNRED
h
m
h
m
m
h
m
h
,FMM
3600
)(),(),(),(),(max),(min,0max
3600
)(),(),(),(),(min),(,0max,0min
3600
)(),(),(),(),(max),(min,0max
3600
)(),(),(),(),(min),(,0max,0min
,1,
4
,,,,,,,,1,,
,1,
3
,,,,,,,,1,,
,1,
2
,,,,,,,,1,,
,1,
1
,,,,,,,,1,,
,,
0,1
0,1
0,
0,
NGR
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hmi
SiRTDm
DASDAStdtFMStFMSRtRTUEDtEDtGRTLOLDAStDOP
DASDAStdtFMStFMSRtRTLEDtEDtGRTUOLDAStDOP
DASDAStdtFMStFMSRtRTUEDtEDtGRTLOLDAStDOP
DASDAStdtFMStFMSRtRTLEDtEDtGRTUOLDAStDOP
GNRED
h
m
h
m
m
h
m
h
,
3600
)(),(),(),(),(max),(min,0max
3600
)(),(),(),(),(min),(,0max,0min
3600
)(),(),(),(),(max),(min,0max
3600
)(),(),(),(),(min),(,0max,0min
,1,
4
,,,,,,,,1,
,1,
3
,,,,,,,,1,
,1,
2
,,,,,,,,1,
,1,
1
,,,,,,,,1,
,,
0,1
0,1
0,
0,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-78
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hihi
T
T
hihihmihmBNDihmihihi
hmi
SiFMMm
DASDAStdtSRtDASRtRTUEDtEDtLRTUOLDAStFMS
DASDAStdtSRtDASRtRTLEDtEDtLRTLOLDAStFMS
DASDAStdtSRtDASRtRTUEDtEDtLRTUOLDAStFMS
DASDAStdtSRtDASRtRTLEDtEDtLRTLOLDAStFMS
LNRED
h
m
h
m
m
h
m
h
,
3600
)(),(),(),(),(max),(0,min,0max
3600
)(),(),(),(),(min),(max,0min
3600
)(),(),(),(),(max),(0,min,0max
3600
)(),(),(),(),(min),(max,0min
,1,
4
,,,,,,,,1,,
,1,
3
,,,,,,,,1,,
,1,
2
,,,,,,,,1,,
,1,
1
,,,,,,,,1,,
,,
0,1
0,1
0,
0,
NGR
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hihi
T
T
hihihmihmBNDihmihii
hmi
SiRTDm
DASDAStdtFMStFMSRtRTUEDtEDtLRTUOLDAStDOP
DASDAStdtFMStFMSRtRTLEDtEDtLRTLOLDAStDOP
DASDAStdtFMStFMSRtRTUEDtEDtLRTUOLDAStDOP
DASDAStdtFMStFMSRtRTLEDtEDtLRTLOLDAStDOP
LNRED
h
m
h
m
m
h
m
h
,
3600
)(),(),(),(),(max),(0,min,0max
3600
)(),(),(),(),(min),(max,0min
3600
)(),(),(),(),(max),(0,min,0max
3600
)(),(),(),(),(min),(max,0min
,1,
4
,,,,,,,,1,
,1,
3
,,,,,,,,1,
,1,
2
,,,,,,,,1,
,1,
1
,,,,,,,,1,
,,
0,1
0,1
0,
0,
Where the integration terminating times are determined as follows for all resources:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-79
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
RTDm
TTtTTOLtFMStRTUEDtEDtDOP
tsTT
TTtTTOLtFMStRTLEDtEDtDOP
tsTT
TTtTTOLtFMStRTUEDtEDtDOP
tsTT
TTtTTOLtFMStRTLEDtEDtDOP
tsTT
FMMm
TTtTTOLtSRtRTUEDtEDtFMS
tsTT
TTtTTOLtSRtRTLEDtEDtFMS
tsTT
TTtTTOLtSRtRTUEDtEDtFMS
tsTT
TTtTTOLtSRtRTLEDtEDtFMS
tsTT
hh
hihmihmBNDii
mi
m
hh
hihmihmBNDii
mi
m
hh
hihmihmBNDii
mi
m
hh
hihmihmBNDii
mi
m
hh
hihmihmBNDihi
mi
m
hh
hihmihmBNDihi
mi
m
hh
hihmihmBNDihi
mi
m
hh
hihmihmBNDihi
mi
m
0,0,1
,,,,,
,
0,0,1
,,,,,
,
0,10,
,,,,,
,
0,10,
,,,,,
,
0,0,1
,,,,,,
,
0,0,1
,,,,,,
,
0,10,
,,,,,,
,
0,10,
,,,,,,
,
)(),(),(max)(
1)(min4
)(),(),(min)(
1)(min3
)(),(),(max)(
1)(max2
)(),(),(min)(
1)(max1
)(),(),(max)(
1)(min4
)(),(),(min)(
1)(min3
)(),(),(max)(
1)(max2
)(),(),(min)(
1)(max1
C.2.1.1.19 Residual Imbalance Energy
The Residual Imbalance Energy may occur at the start and/or end of the Trading Hour, and only for as long as the Slope
Direction of either the Ramping FMS for FMM , or Dispatch Operating Point for RTD market, as applicable, remains increasing
or decreasing, as the relevant case may be. The Residual Imbalance Energy at the top and bottom of the Trading Hour can be
determined by searching forward from the start of the Trading Hour and backward from the end of the Trading Hour as follows:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-80
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
ECATIEHPDNGR
khmikhmikhmi
fhmifhmifhmi
SSSSi
RTDmBRIETRIERIE
FMMmBRIETRIERIE
,,,,,,,,,
,,,,,,,,,
ECATIEHPDNGRkhRTDifhFMMikhi SSSSiRIERIERIE ,,,,,,,,
The total RIE shall be settled as 5 minute RTD values.
ECATIEHPDNGR
hihhi
T
T
hihihmihmBNDihmihihihi
hihhi
T
T
hihihmihmBNDihmihihihi
hmi
SSSSiFMMm
DASTFMStdtSRtDASRtRTUEDtEDtRTLOLDASDAStFMS
DASTFMStdtSRtDASRtRTLEDtEDtRTUOLDASDAStFMS
TRIEm
h
m
h
,
)(3600
)(),(),(),(),(,,max)(,0max
)(3600
)(),(),(),(),(,,min)(,0min
,0,,
6
,,,,,,,,,1,,
,0,,
5
,,,,,,,,,1,,
,,
0,
0,
ECATIEHPDNGR
hihi
T
T
hihihmihmBNDihmihihii
hihi
T
T
hihihmihmBNDihmihihii
hmi
SSSSiRTDm
DASTDOPtdtFMStFMSRtRTUEDtEDtRTLOLDASDAStDOP
DASTDOPtdtFMStFMSRtRTLEDtEDtRTUOLDASDAStDOP
TRIEm
h
m
h
,
)(3600
)(),(),(),(),(,,max)(,0max
)(3600
)(),(),(),(),(,,min)(,0min
,0,
6
,,,,,,,,,1,
,0,
5
,,,,,,,,,1,
,,
0,
0,
ECATIEHPDNGR
hihhi
T
T
hihihmihmBNDihmihihihi
hihhi
T
T
hihihmihmBNDihmihihihi
hmi
SSSSiFMMm
DASTFMStdtSRtDASRtRTUEDtEDtRTLOLDASDAStFMS
DASTFMStdtSRtDASRtRTLEDtEDtRTUOLDASDAStFMS
BRIEh
m
h
m
,
)(3600
)(),(),(),(),(,,max)(,0max
)(3600
)(),(),(),(),(,,min)(,0min
,0,1.
8
,,,,,,,,,1,.
,0,1,
7
,,,,,,,,,1,,
,, 0,1
0,1
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-81
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
ECATIEHPDNGR
hihi
T
T
hihihmihmBNDihmihihii
hihi
T
T
hihihmihmBNDihmihihii
hmi
SSSSiRTDm
DASTDOPtdtFMStFMSRtRTUEDtEDtRTLOLDASDAStDOP
DASTDOPtdtFMStFMSRtRTLEDtEDtRTUOLDASDAStDOP
BRIEh
m
h
m
,
)(3600
)(),(),(),(),(,,max)(,0max
)(3600
)(),(),(),(),(,,min)(,0min
,0,1
8
,,,,,,,,,1,
,0,1
7
,,,,,,,,,1,
,, 0,1
0,1
NGR
khmikhmikhmikhmikhmi
fhmifhmifhmifhmifhmi
Si
RTDmLBRIEGBRIELTRIEGTRIERIE
FMMmLBRIEGBRIELTRIEGTRIERIE
,,,,,,,,,,,,,,,
,,,,,,,,,,,,,,,
NGRkhRTDifhFMMikhi SiRIERIERIE ,,,,,,,,
The total RED shall be settled as 5 minute RTD values.
NGR
hihhi
T
T
hihmihmBNDihmihihihi
hihhi
T
T
hihmihmBNDihmihihihi
hmi
SiFMMm
DASTFMStdtDASRtRTUEDtEDtGRTLOLDASDAStFMS
DASTFMStdtDASRtRTLEDtEDtGRTUOLDASDAStFMS
GTRIEm
h
m
h
,
)(3600
)(),(),(),(,,max)(,0max
)(3600
)(),(),(),(,,min)(,0max,0min
,0,,
6
,,,,,,,,1,,
,0,,
5
,,,,,,,,1,,
,,
0,
0,
NGR
hihi
T
T
hihmihmBNDihmihihii
hihi
T
T
hihmihmBNDihmihihii
hmi
SiRTDm
DASTDOPtdtFMSRtRTUEDtEDtGRTLOLDASDAStDOP
DASTDOPtdtFMSRtRTLEDtEDtGRTUOLDASDAStDOP
GTRIEm
h
m
h
,
)(3600
)(),(),(),(,,max)(,0max
)(3600
)(),(),(),(,,min)(,0max,0min
,0,
6
,,,,,,,,1,
,0,
5
,,,,,,,,1,
,,
0,
0,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-82
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
hihhi
T
T
hihmihmBNDihmihihihi
hihhi
T
T
hihmihmBNDihmihihihi
hmi
SiFMMm
DASTFMStdtDASRtRTUEDtEDtLRTUOLDASDAStFMS
DASTFMStdtDASRtRTLEDtEDtLRTLOLDASDAStFMS
LTRIEm
h
m
h
,
)(3600
)(),(),(),(,,max)(,0min,0max
)(3600
)(),(),(),(,,min)(,0min
,0,,
6
,,,,,,,,1,,
,0,,
5
,,,,,,,,1,,
,,
0,
0,
NGR
hihi
T
T
hihmihmBNDihmihihii
hihi
T
T
hihmihmBNDihmihihii
hmi
SiRTDm
DASTDOPtdtFMSRtRTUEDtEDtLRTUOLDASDAStDOP
DASTDOPtdtFMSRtRTLEDtEDtLRTLOLDASDAStDOP
LTRIEm
h
m
h
,
)(3600
)(),(),(),(,,max)(,0min,0max
)(3600
)(),(),(),(,,min)(,0min
,0,
6
,,,,,,,,1,
,0,
5
,,,,,,,,1,
,,
0,
0,
NGR
hihhi
T
T
hihmihmBNDihmihihihi
hihhi
T
T
hihmihmBNDihmihihihi
hmi
SiFMMm
DASTFMStdtDASRtRTUEDtEDtGRTLOLDASDAStFMS
DASTFMStdtDASRtRTLEDtEDtGRTUOLDASDAStFMS
GBRIEh
m
h
m
,
)(3600
)(),(),(),(,,max)(,0max
)(3600
)(),(),(),(,,min)(,0max,0min
,0,1,
8
,,,,,,,,1,,
,0,1,
7
,,,,,,,,1,,
,, 0,1
0,1
NGR
hihi
T
T
hihmihmBNDihmihihii
hihi
T
T
hihmihmBNDihmihihii
hmi
SiRTDm
DASTDOPtdtFMSRtRTUEDtEDtGRTLOLDASDAStDOP
DASTDOPtdtFMSRtRTLEDtEDtGRTUOLDASDAStDOP
GBRIEh
m
h
m
,
)(3600
)(),(),(),(,,max)(,0max
)(3600
)(),(),(),(,,min)(,0max,0min
,0,1
8
,,,,,,,,1,
,0,1
7
,,,,,,,,1,
,, 0,1
0,1
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-83
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
hihhi
T
T
hihmihmBNDihmihihihi
hihhi
T
T
hihmihmBNDihmihihihi
hmi
SiFMMm
DASTFMStdtDASRtRTUEDtEDtLRTUOLDASDAStFMS
DASTFMStdtDASRtRTLEDtEDtLRTLOLDASDAStFMS
LBRIEh
m
h
m
,
)(3600
)(),(),(),(,,max)(,0min,0max
)(3600
)(),(),(),(,,min)(,0min
,0,1,
8
,,,,,,,,1,,
,0,1,
7
,,,,,,,,1,,
,, 0,1
0,1
NGR
hihi
T
T
hihmihmBNDihmihihii
hihi
T
T
hihmihmBNDihmihihii
hmi
SiRTDm
DASTDOPtdtFMSRtRTUEDtEDtLRTUOLDASDAStDOP
DASTDOPtdtFMSRtRTLEDtEDtLRTLOLDASDAStDOP
LBRIEh
m
h
m
,
)(3600
)(),(),(),(,,max)(,0min,0max
)(3600
)(),(),(),(,,min)(,0min
,0,1
8
,,,,,,,,1,
,0,1
7
,,,,,,,,1,
,, 0,1
0,1
Where the integration terminating times are determined as follows for all resources:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-84
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
TIEHPD
hh
hmihmBNDihihii
mi
m
hh
hmihmBNDihihii
mi
m
hh
hmihmBNDihihii
mi
m
hh
hmihmBNDihihii
mi
m
hh
hmihmBNDihihihi
mi
m
hh
hmihmBNDihihihi
mi
m
hh
hmihmBNDihihihi
mi
m
hh
hmihmBNDihihihi
mi
m
SSi
RTDm
TTtTTOLtRTUEDtEDDASDAStDOP
tsTT
TTtTTOLtRTLEDtEDDASDAStDOP
tsTT
TTtTTOLtRTUEDtEDDASDAStDOP
tsTT
TTtTTOLtRTLEDtEDDASDAStDOP
tsTT
FMMm
TTtTTOLtRTUEDtEDDASDAStFMS
tsTT
TTtTTOLtRTLEDtEDDASDAStFMS
tsTT
TTtTTOLtRTUEDtEDDASDAStFMS
tsTT
TTtTTOLtRTLEDtEDDASDAStFMS
tsTT
0,0,1
,,,,,1,
,
0,0,1
,,,,,1,
,
0,10,
,,,,,1,
,
0,10,
,,,,,1,
,
0,0,1
,,,,,1,,
,
0,0,1
,,,,,1,,
,
0,10,
,,,,,1,,
,
0,10,
,,,,,1,,
,
)(),(,,max)(
1)(min8
)(),(,,min)(
1)(min7
)(),(,,max)(
1)(max6
)(),(,,min)(
1)(max5
)(),(,,max)(
1)(min8
)(),(,,min)(
1)(min7
)(),(,,max)(
1)(max6
)(),(,,min)(
1)(max5
The 15-minute Trading Interval Reference for TRIE, GTRIE, and LTRIE is the one that includes or ends at the backward terminating time going beyond hourly boundaries, calculated as follows:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-85
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
RTDmTTtT
TOLtRTUEDtEDDASDAStDOP
tsT
TOLtRTLEDtEDDASDAStDOP
tsT
FMMmTTtT
TOLtRTUEDtEDDASDAStFMS
tsT
TOLtRTLEDtEDDASDAStFMS
tsT
TB
h
hmihmBNDihihii
mi
hmihmBNDihihii
mi
h
hmihmBNDihihihi
mi
hmihmBNDihihihi
mi
mref
00,
,,,,,1,
,
,,,,,1,
,
00,
,,,,,1,,
,
,,,,,1,,
,
,
)(),(,,max)(
1)(min
,)(),(,,min)(
1)(min
min
)(),(,,max)(
1)(min
,)(),(,,min)(
1)(min
min
Note: mrefTB , can be different between FMM and RTD.
The 15-minute Trading Interval Reference for BRIE, GBRIE, and LBRIE is the one that includes or starts at the forward terminating time going beyond hourly boundaries, calculated as follows:
RTDmTTtT
TOLtRTUEDtEDDASDAStDOP
tsT
TOLtRTLEDtEDDASDAStDOP
tsT
FMMmTTtT
TOLtRTUEDtEDDASDAStDOP
tsT
TOLtRTLEDtEDDASDAStDOP
tsT
TF
Nh
hmihmBNDihihii
mi
hmihmBNDihihii
mi
Nh
hmihmBNDihihii
mi
hmihmBNDihihii
mi
mref
0,1
,,,,,1,
,
,,,,,1,
,
0,1
,,,,,1,
,
,,,,,1,
,
,
)(),(,,max)(
1)(max
,)(),(,,min)(
1)(max
max
)(),(,,max)(
1)(max
,)(),(,,min)(
1)(max
max
Note: mrefTF , can be different between FMM and RTD.
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-86
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
If the search reaches the end or start of the target Trading Day, it shall continue into subsequent or previous Trading Days as needed.
Note: In the above refTB and refTF formulae, h is the current hour where the conditions for the search are evaluated and it shall
be decremented or incremented accordingly as the search proceeds to previous or subsequent hours.
The 15-minute mitigated Energy Bid of the 15-minute Trading Interval Reference shall be used in the settlement of Residual Imbalance Energy.
C.2.1.1.20 Derate Energy
The Derate Energy is the sum of the Lower Derate Energy due to Minimum Load overrates and the Upper Derate Energy due
to Maximum Capacity derates:
HPDGEN
khmikhmikhmi
fhmifhmifhmi
SSi
RTDmUDRELDREDRE
FMMmUDRELDREDRE
,,,,,,,,,
,,,,,,,,,
The Derate Energy for NGR is the sum of the Lower Derate Energy due to GMIN/LMIN overrates and the Upper Derate Energy
due to GMAX/LMAX derates:
NGR
khmikhmikhmikhmikhmi
fhmifhmifhmifhmifhmi
Si
RTDmLUDRELLDREGUDREGLDREDRE
FMMmLUDRELLDREGUDREGLDREDRE
,,,,,,,,,,,,,,,
,,,,,,,,,,,,,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-87
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
The Lower Derate Energy, including any overlap with LFE or BED, but excluding SRE, is calculated as follows:
HPDGEN
T
T
hihihmihmBNDihmii
khmi
T
T
hihihmihmBNDihmihi
fhmi
SSi
RTDmtdtFMStFMSRtRTUEDtEDtRTLOLtDOP
LDRE
FMMmtdDAStDASRtRTUEDtEDtRTLOLtFMS
LDRE
kh
kh
fh
fh
,
1,
,
1,
3600
)(),(),(),(max)(),(min,0max
3600
),(),(),(max)(),(min,0max
,,,,,,,,
,,,
,,,,,,,,,
,,,
HPDGENT
T
hihmihmBNDihihihmihi
T
T
hihihihmihmBNDihmihi
fhmi SSiFMMm
tdtDASRtRTUEDtEDtSRDAStRTLOLtFMS
tdtSRDAStDASRtRTUEDtEDtRTLOLtFMS
LDREfh
fh
fh
fh
,
1,
,
1,
3600
)(),(),(max)(,),(),(min,0max
3600
)(,),(),(),(max)(),(min,0max
,,,,,`,,,,,
,,,,,,,,,,
,,,
HPDGENT
T
hihmihmBNDihihmii
T
T
hihihmihmBNDihmii
khmi SSiRTDm
tdtFMSRtRTUEDtEDtFMStRTLOLtDOP
tdtFMStFMSRtRTUEDtEDtRTLOLtDOP
LDREkh
kh
kh
kh
,
1,
,
1,
3600
)(),(),(max)(),(),(min,0max
3600
)(),(),(),(max)(),(min,0max
,,,,,,,,
,,,,,,,,
,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-88
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGRT
T
hihmihmBNDiMINihihihmihi
T
T
hihihihmihmBNDiMINihmihi
fhmi SiFMMm
tdtDASRtRTUEDtEDGtSRDAStGRTLOLtFMS
tdtSRDAStDASRtRTUEDtEDGtGRTLOLtFMS
GLDREfh
fh
fh
fh
,
1,
,
1,
3600
)(),(),(,max)(,),(),(min,0max
3600
)(,),(),(),(,max)(),(min,0max
,,,,,,,,,,
,,,,,,,,,,
,,,
NGRT
T
hihmihmBNDiMINihihmii
T
T
hihihmihmBNDiMINihmii
khmi SiRTDm
tdtFMSRtRTUEDtEDGtFMStGRTLOLtDOP
tdtFMStFMSRtRTUEDtEDGtGRTLOLtDOP
GLDREkh
kh
kh
kh
,
1,
,
1,
3600
)(),(),(,max)(),(),(min,0max
3600
)(),(),(),(,max)(),(min,0max
,,,,,,,,
,,,,,,,,
,,,
NGRT
T
hihmihmBNDiMINihihihmihi
T
T
hihihihmihmBNDiMINihmihi
fhmi SiFMMm
tdtDASRtRTLEDtEDLtSRDAStLRTLOLtFMS
tdtSRDAStDASRtRTLEDtEDLtLRTLOLtFMS
LLDREfh
fh
fh
fh
,
1,
,
1,
3600
)(),(),(,min)(,),(),(max,0min
3600
)(,),(),(),(,min)(),(max,0min
,,,,,,,,,,
,,,,,,,,,,
,,,
NGRT
T
hihmihmBNDiMINihihmii
T
T
hihihmihmBNDiMINihmii
khmi SiRTDm
tdtFMSRtRTLEDtEDLtFMStLRTLOLtDOP
tdtFMStFMSRtRTLEDtEDLtLRTLOLtDOP
LLDREkh
kh
kh
kh
,
1,
,
1,
3600
)(),(),(,min)(),(),(max,0min
3600
)(),(),(),(,min)(),(max,0min
,,,,,,,,
,,,,,,,,
,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-89
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
The Upper Derate Energy, including any overlap with LFE or BED, but excluding SRE, is calculated as follows:
HPDGEN
T
T
hihihmihmBNDihmii
khmi
T
T
hihihmihmBNDihmihi
fhmi
SSi
RTDmtdtFMStFMSRtRTLEDtEDtRTUOLtDOP
UDRE
FMMmtdDAStDASRtRTLEDtEDtRTUOLtFMS
UDRE
kh
kh
fh
fh
,
1,
,
1,
3600
)(),(),(),(min)(),(max,0min
3600
),(),(),(min)(),(max,0min
,,,,,,,,
,,,
,,,,,,,,,
,,,
HPDGENT
T
hihmihmBNDihihihmihi
T
T
hihihihmihmBNDihmihi
fhmi SSiFMMm
tdtDASRtRTLEDtEDtSRDAStRTUOLtFMS
tdtSRDAStDASRtRTLEDtEDtRTUOLtFMS
UDREfh
fh
fh
fh
,
1,
,
1,
3600
)(),(),(min)(,),(),(max,0min
3600
)(,),(),(),(min)(),(max,0min
,,,,,,,,,,
,,,,,,,,,,
,,,
HPDGENT
T
hihmihmBNDihihmii
T
T
hihihmihmBNDihmii
khmi SSiRTDm
tdtFMSRtRTLEDtEDtFMStRTUOLtDOP
tdtFMStFMSRtRTLEDtEDtRTUOLtDOP
UDREkh
kh
kh
kh
,
1,
,
1,
3600
)(),(),(min)(),(),(max,0min
3600
)(),(),(),(min)(),(max,0min
,,,,,,,,
,,,,,,,,
,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-90
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGRT
T
hihmihmBNDihihihmihi
T
T
hihihihmihmBNDihmihi
fhmi SiFMMm
tdtDASRtRTLEDtEDtSRDAStGRTUOLtFMS
tdtSRDAStDASRtRTLEDtEDtGRTUOLtFMS
GUDREfh
fh
fh
fh
,
1,
,
1,
3600
)(),(),(min)(,),(),(max,0min
3600
)(,),(),(),(min)(),(max,0min
,,,,,,,,,,
,,,,,,,,,,
,,,
NGRT
T
hihmihmBNDihihmii
T
T
hihihmihmBNDihmii
khmi SiRTDm
tdtFMSRtRTLEDtEDtFMStGRTUOLtDOP
tdtFMStFMSRtRTLEDtEDtGRTUOLtDOP
GUDREkh
kh
kh
kh
,
1,
,
1,
3600
)(),(),(min)(),(),(max,0min
3600
)(),(),(),(min)(),(max,0min
,,,,,,,,
,,,,,,,,
,,,
NGRT
T
hihmihmBNDihihihmihi
T
T
hihihihmihmBNDihmihi
fhmi SiFMMm
tdtDASRtRTUEDtEDtSRDAStLRTUOLtFMS
tdtSRDAStDASRtRTUEDtEDtLRTUOLtFMS
LUDREfh
fh
fh
fh
,
1,
,
1,
3600
)(),(),(max)(,),(),(min,0max
3600
)(,),(),(),(max)(),(min,0max
,,,,,,,,,,
,,,,,,,,,,
,,,
NGRT
T
hihmihmBNDihihmii
T
T
hihihmihmBNDihmii
khmi SiRTDm
tdtFMSRtRTUEDtEDtFMStLRTUOLtDOP
tdtFMStFMSRtRTUEDtEDtLRTUOLtDOP
LUDREkh
kh
kh
kh
,
1,
,
1,
3600
)(),(),(max)(),(),(min,0max
3600
)(),(),(),(max)(),(min,0max
,,,,,,,,
,,,,,,,,
,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-91
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
C.2.1.1.21 Exceptional Dispatch Energy
The Exceptional Dispatch Energy, including any overlap with LFE or BED, but excluding SRE and RTPE, is calculated as
follows:
HPD
hihBNDi
T
T
hihihmihmBNDihi
hihBNDi
T
T
hihihmihmBNDihi
fmi SiFMMm
tDASRtEDtdDAStDASRtRTLEDtEDtFMS
tDASRtEDtdDAStDASRtRTUEDtEDtFMS
EDEfh
fh
fh
fh
,
)()(3600
),(),(min)(),(,0max,0min
)()(3600
),(),(,0max)(),(min,0max
,,
,,,,,,,
,,
,,,,,,,
,, ,
1,
,
1,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-92
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
HPD
hihBNDi
T
T
hihihmihmBNDii
hihBNDi
T
T
hihihmihmBNDii
khmi SiRTDm
tFMSRtEDtdtFMStFMSRtRTLEDtEDtDOP
tFMSRtEDtdtFMStFMSRtRTUEDtEDtDOP
EDEkh
kh
kh
kh
,
)()(3600
)(),(),(min)(),(,0max,0min
)()(3600
)(),(),(,0max)(),(min,0max
,,
,,,,,,
,,
,,,,,,
,,, ,
1,
,
1,
HPDNGR
hihmBNDiT
T
hihmihihihmBNDihi
T
T
hihihihmihmBNDihi
hihmBNDiT
T
hihmihihihmBNDihi
T
T
hihihihmihmBNDihi
fhmi SSiFMMm
tDASRtED
tdtDASRtRTLEDtSRDAStEDtFMS
tdtSRDAStDASRtRTLEDtEDtFMS
tDASRtED
tdtDASRtRTUEDtSRDAStEDtFMS
tdtSRDAStDASRtRTUEDtEDtFMS
EDE
fh
fh
fh
fh
fh
fh
fh
fh
,
)()(
3600
)(),(min)(,),(),(,0max,0min
3600
)(,),(),(min)(),(,0max,0min
)()(
3600
)(),(,0max)(,),(),(min,0max
3600
)(,),(),(,0max)(),(min,0max
,,,
,,,,,,,,
,,,,,,,,
,,,
,,,,,,,,
,,,,,,,,
,,,
,
1,
,
1,
,
1,
,
1,
HPDNGR
hihmBNDiT
T
hihmihihmBNDii
T
T
hihihmihmBNDii
hihmBNDiT
T
hihmihihmBNDii
T
T
hihihmihmBNDii
khmi SSiRTDm
tFMSRtED
tdtFMSRtRTLEDtFMStEDtDOP
tdtFMStFMSRtRTLEDtEDtDOP
tFMSRtED
tdtFMSRtRTUEDtFMStEDtDOP
tdtFMStFMSRtRTUEDtEDtDOP
EDE
kh
kh
kh
kh
kh
kh
kh
kh
,
)()(
3600
)(),(min)(),(),(,0max,0min
3600
)(),(),(min)(),(,0max,0min
)()(
3600
)(),(,0max)(),(),(min,0max
3600
)(),(),(,0max)(),(min,0max
,,,
,,,,,,
,,,,,,
,,,
,,,,,,
,,,,,,
,,,
,
1,
,
1,
,
1,
,
1,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-93
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
hihmBNDi
T
T
hihmihihihmBNDihi
T
T
hihihihmihmBNDihi
T
T
hihmiMINihihihmBNDihi
T
T
hihihihmiMINihmBNDihi
hihmBNDi
T
T
hihmihihihmBNDihi
T
T
hihihihmihmBNDihi
T
T
hihmiMINihihihmBNDihi
T
T
hihihihmiMINihmBNDihi
fhmi SiFMMm
tDASRtED
tdtDASRtRTLEDtSRDAStEDtFMS
tdtSRDAStDASRtRTLEDtEDtFMS
tdtDASRtRTLEDLtSRDAStEDtFMS
tdtSRDAStDASRtRTLEDLtEDtFMS
tDASRtED
tdtRDAStRTUEDtSRDAStEDtFMS
tdtSRDAStDASRtRTUEDtEDtFMS
tdtRDAStRTUEDGtSRDAStEDtFMS
tdtSRDAStDASRtRTUEDGtEDtFMS
EDE
fh
fh
fh
fh
fh
fh
fh
fh
fh
fh
fh
fh
fh
fh
fh
fh
,
)()(
3600
)(),(min)(,),(),(,0max,0min
3600
)(,),(),(min)(),(,0max,0min
3600
)(),(,min)(,),(),(max,0min
3600
)(,),(),(,min)(),(max,0min
)()(
3600
)(,)(max)(,,)(),(,0min,0max
3600
)(,),(),(max)(),(,0min,0max
3600
)(,)(,max)(,,)(),(min,0max
3600
)(,),(),(,max)(),(min,0max
,,,
,,,,,,,,
,,,,,,,,
,,,,,,,,
,,,,,,,,
,,,
,,,,,,,,
,,,,,,,,
,,,,,,,,
,,,,,,,,
,,,
,
1,
,
1,
,
1,
,
1,
,
1,
,
1,
,
1,
,
1,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-94
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
hihmBNDi
T
T
hihmihihmBNDii
T
T
hihihmihmBNDii
T
T
hihmiMINihihmBNDii
T
T
hihihmiMINihmBNDii
hihmBNDi
T
T
hihmihihmBNDii
T
T
hihihmihmBNDii
T
T
hihmiMINihihmBNDii
T
T
hihihmiMINihmBNDii
khmi SiRTDm
tFMSRtED
tdtFMSRtRTLEDtFMStEDtDOP
tdtFMStFMSRtRTLEDtEDtDOP
tdtFMSRtRTLEDLtFMStEDtDOP
tdtFMStFMSRtRTLEDLtEDtDOP
tFMSRtED
tdtRFMStRTUEDtFMStEDtDOP
tdtFMStFMSRtRTUEDtEDtDOP
tdtRFMStRTUEDGtFMStEDtDOP
tdtFMStFMSRtRTUEDGtEDtDOP
EDE
kh
kh
kh
kh
kh
kh
kh
kh
kh
kh
kh
kh
kh
kh
kh
kh
,
)()(
3600
)(),(min)(),(),(,0max,0min
3600
)(),(),(min)(),(,0max,0min
3600
)(),(,min)(),(),(max,0min
3600
)(),(),(,min)(),(max,0min
)()(
3600
)(,)(max)(,)(),(,0min,0max
3600
)(),(),(max)(),(,0min,0max
3600
)(,)(,max)(,)(),(min,0max
3600
)(),(),(,max)(),(min,0max
,,,
,,,,,,
,,,,,,
,,,,,,
,,,,,,
,,,
,,,,,,
,,,,,,
,,,,,,
,,,,,,
,,,
,
1,
,
1,
,
1,
,
1,
,
1,
,
1,
,
1,
,
1,
C.2.1.1.22 Optimal Energy
Any Instructed Imbalance Energy that remains unaccounted is Optimal Energy:
NGR
khmikhmikhmikhmikhmikhmikhmikhmikhmikhmi
fhmifhmifhmifhmifhmifhmifhmifhifhmifhmifhmi
Si
RTDmEDEDRERIEREDRTMLERTPELFEBEDIIEOE
FMMmEDEDRERIEREDRTMLERTPELFESREBEDIIEOE
,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,
,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,
NGR
khmikhmikhmikhmikhmikhmikhmikhmikhmikhmi
fhmifhmifhmifhmifhmifhmifhmifhifhmifhmifhmi
Si
RTDmEDEDRERIEREDRTMLERTMGELFEBEDIIEOE
FMMmEDEDRERIEREDRTMLERTMGELFESREBEDIIEOE
,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,
,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-95
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
For Non-Dynamic System Resources, the Optimal Energy is calculated as the sum of the extra-marginal and infra-marginal
portions as follows:
HPD
T
T
hihmihi
T
T
hihmihmBNDihmihi
T
T
hiMINihmihi
T
T
hihmihmBNDihmihi
fhmi SiFMMm
tdtDASRtRTLEDtFMS
tdtDASRtRTLEDtEDtRTUOLtFMS
tdtDASRPtRTUEDtFMS
tdtDASRtRTUEDtEDtRTLOLtFMS
OE
fh
fh
fh
fh
fh
fh
fh
fh
,
1,
,
1,
,
1,
,
1,
3600
)()(),(,0max,0min
3600
)(),(),(),(min)(,0max,0min
3600
)(,max)(),(min,0max
3600
)(),(),(),(,0max)(,0max
,,,,
,,,,,,,,
,,,,
,,,,,,,,
,,,
HPD
T
T
hihmii
T
T
hihmihmBNDihmii
T
T
hiMINihmii
T
T
hihmihmBNDihmii
khmi SiRTDm
tdtFMSRtRTLEDtDOP
tdtFMSRtRTLEDtEDtRTUOLtDOP
tdtFMSRPtRTUEDtDOP
tdtFMSRtRTUEDtEDtRTLOLtDOP
OE
kh
kh
kh
kh
kh
kh
kh
kh
,
1,
,
1,
,
1,
,
1,
3600
)()(),(,0max,0min
3600
)(),(),(),(min)(,0max,0min
3600
)(,max)(),(min,0max
3600
)(),(),(),(,0max)(,0max
,,,
,,,,,,,
,,,
,,,,,,,
,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-96
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
For non-generator resources (NGRs), for which SRE/RED/RIE may exist, the Optimal Energy is calculated as the sum of the
extra-marginal and infra-marginal portions that may overlap, but excluding SRE/RED/RIE and RTPE. The Non-overlapping
Optimal Energy is calculated as follows:
NGR
T
T
hihihihmihiMINi
TTT
TTT
hihihihmihmBNDihmihiMINi
T
T
hihihmiMINihmihi
TTT
TTT
hihihihmihmBNDihmihi
fhmi SiFMMm
tdtSRDAStDASRtRTLEDtFMSG
tdtSRDAStDASRtRTLEDtEDtGRTUOLtFMSG
tdtSRDAStDASRGtRTUEDtFMS
tdtSRDAStDASRtRTUEDtEDtGRTLOLtFMS
GNOE
fh
fh
mmfh
mmfh
kh
fh
mmfh
mmfh
,
1,
,
1,
,
1,
,
1,
3600
)(,),(min)(),(,max,0min
3600
)(,),(),(),(),(min)(,max,0min
3600
)(,),(,max)(),(min,0max
3600
)(,),(),(),(),(max)(,0max
,,,,,,
7,3,min
5,1,max
,,,,,,,,,,
,,,,,,,
8,4,min
6,2,max
,,,,,,,,,,,
,,,
NGR
T
T
hihihmiiMINi
TTT
TTT
hihihmihmBNDihmiiMINi
T
T
hihmiMINihmii
TTT
TTT
hihihmihmBNDihmii
khmi SiRTDm
tdtFMStFMSRtRTLEDtDOPG
tdtFMStFMSRtRTLEDtEDtGRTUOLtDOPG
tdtFMStFMSRGtRTUEDtDOP
tdtFMStFMSRtRTUEDtEDtGRTLOLtDOP
GNOE
kh
kh
mmkh
mmkh
kh
kh
mmkh
mmkh
,
1,
,
1,
,
1,
,
1,
3600
)(),(min)(),(,max,0min
3600
)(),(),(),(),(min)(,max,0min
3600
)(),(,max)(),(min,0max
3600
)(),(),(),(),(max)(,0max
,,,,
7,3,min
5,1,max
,,,,,,,,
,,,,,
8,4,min
6,2,max
,,,,,,,,,
,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-97
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
T
T
hihihihmihiMINi
TTT
TTT
hihihihmihmBNDihmihiMINi
T
T
hihihiMINihmihi
TTT
TTT
hihihihmihmBNDihmihi
fhmi SiFMMm
tdtSRDAStDASRtRTUEDtFMSL
tdtSRDAStDASRtRTUEDtEDtLRTUOLtFMSL
tdtSRDAStDASRLtRTLEDtFMS
tdtSRDAStDASRtRTLEDtEDtLRTLOLtFMS
LNOE
fh
fh
mmfh
mmfh
fh
fh
mmfh
mmfh
,
1,
,
1,
,
1,
,
1,
3600
)(,),(max)(),(,min,0max
3600
)(,),(),(),(),(max)(,min,0max
3600
)(,),(,min)(),(max,0min
3600
)(,),(),(),(),(min)(,0min
,,,,,,
7,3,min
5,1,max
,,,,,,,,,,
,,,,,,
8,4,min
6,2,max
,,,,,,,,,,
,,,
NGR
T
T
hihihmiiMINi
TTT
TTT
hihihmihmBNDihmiiMINi
T
T
hihiMINihmii
TTT
TTT
hihihmihmBNDihmii
khmi SiRTDm
tdtFMStFMSRtRTUEDtDOPL
tdtFMStFMSRtRTUEDtEDtLRTUOLtDOPL
tdtFMStFMSRLtRTLEDtDOP
tdtFMStFMSRtRTLEDtEDtLRTLOLtDOP
LNOE
kh
kh
mmkh
mmkh
kh
kh
mmkh
mmkh
,
1,
,
1,
,
1,
,
1,
3600
)(),(max)(),(,min,0max
3600
)(),(),(),(),(max)(,min,0max
3600
)(),(,min)(),(max,0min
3600
)(),(),(),(),(min)(,0min
,,,,
7,3,min
5,1,max
,,,,,,,,
,,,,
8,4,min
6,2,max
,,,,,,,,
,,,
The Overlapping Optimal Energy, which may exist for Load Following Resources, is calculated as follows:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-98
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGRMSS
T
T
hihihihmihi
T
T
hihmihmBNDihmihihihi
T
T
hiMINihihihmihi
T
T
hihmihmBNDihmihihihi
fhmi SSiFMMm
tdtDASRtSRDAStRTLEDtFMS
tdtDASRtRTLEDtEDtRTUOLtSRDAStFMS
tdtDASRPtSRDAStRTUEDtFMS
tdtDASRtRTUEDtEDtRTLOLtSRDAStFMS
OOE
fh
fh
fh
fh
fh
fh
fh
fh
,
1,
,
1,
,
1,
,
1,
3600
)()(,),(),(,0max,0min
3600
)(),(),(),(min)(,),(,0max,0min
3600
)(,max)(,),(),(min,0max
3600
)(),(),(),(,0max)(,),(min,0max
,,,,,,
,,,,,,,,,,
,,,,,,
,,,,,,,,,,
,,,
NGRMSS
T
T
hihihmii
T
T
hihmihmBNDihmihii
T
T
hiMINihihmii
T
T
hihmihmBNDihmihii
khmi SSiRTDm
tdtFMSRtFMStRTLEDtDOP
tdtFMSRtRTLEDtEDtRTUOLtFMStDOP
tdtFMSRPtFMStRTUEDtDOP
tdtFMSRtRTUEDtEDtRTLOLtFMStDOP
OOE
kh
kh
kh
kh
kh
kh
kh
kh
,
1,
,
1,
,
1,
,
1,
3600
)()(),(),(,0max,0min
3600
)(),(),(),(min)(),(,0max,0min
3600
)(,max)(),(),(min,0max
3600
)(),(),(),(,0max)(),(min,0max
,,,,
,,,,,,,,
,,,,
,,,,,,,,
,,,
The Overlapping Optimal Energy, which may exist for Non-Generator Resources, is calculated as follows:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-99
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGRMSS
T
T
hmihihihmihiMINi
T
T
hmihmihmBNDihmihihihiMINi
T
T
hmiMINihihihmihi
T
T
hihmihmBNDihmihihihi
fhmi SSiFMMm
tdtDASRtSRDAStRTLEDtFMSG
tdtDASRtRTLEDtEDtGRTUOLtSRDAStFMSG
tdtDASRGtSRDAStRTUEDtFMS
tdtDASRtRTUEDtEDtGRTLOLtSRDAStFMS
GOOE
fh
fh
fh
fh
fh
fh
fh
fh
,
1,
,
1,
,
1,
,
1,
3600
)()(,),(),(,max,0min
3600
)(),(),(),(min)(,),(,max,0min
3600
)(,max)(,),(),(min,0max
3600
)(),(),(),(max)(,),(min,0max
,,,,,,,
,,,,,,,,,,,
,,,,,,,
,,,,,,,,,,
,,,
NGRMSS
T
T
hmihihmiiMINi
T
T
hmihmihmBNDihmihiiMINi
T
T
hmiMINihihmii
T
T
hihmihmBNDihmihii
khmi SSiRTDm
tdtFMSRtFMStRTLEDtDOPG
tdtFMSRtRTLEDtEDtGRTUOLtFMStDOPG
tdtFMSRGtFMStRTUEDtDOP
tdtFMSRtRTUEDtEDtGRTLOLtFMStDOP
GOOE
kh
kh
kh
kh
kh
kh
kh
kh
,
1,
,
1,
,
1,
,
1,
3600
)()(),(),(,max,0min
3600
)(),(),(),(min)(),(,max,0min
3600
)(,max)(),(),(min,0max
3600
)(),(),(),(max)(),(min,0max
,,,,,
,,,,,,,,,
,,,,,
,,,,,,,,
,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-100
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGRMSS
T
T
hmihihihmihiMINi
T
T
hihmihmBNDihmihihihiMINi
T
T
hiMINihihihmihi
T
T
hihmihmBNDihmihihihi
fhmi SSiFMMm
tdtDASRtSRDAStRTUEDtFMSL
tdtDASRtRTUEDtEDtLRTUOLtSRDAStFMSL
tdtDASRLtSRDAStRTLEDtFMS
tdtDASRtRTLEDtEDtLRTLOLtSRDAStFMS
LOOE
fh
fh
fh
fh
fh
fh
fh
fh
,
1,
,
1,
,
1,
,
1,
3600
)()(,),(),(,min,0max
3600
)(),(),(),(max)(,),(,min,0max
3600
)(,min)(,),(),(max,0min
3600
)(),(),(),(min)(,),(max,0min
,,,,,,,
,,,,,,,,,,,
,,,,,,
,,,,,,,,,,
,,,
NGRMSS
T
T
hmihihmiiMINi
T
T
hihmihmBNDihmihiiMINi
T
T
hiMINihihmii
T
T
hihmihmBNDihmihii
khmi SSiRTDm
tdtFMSRtFMStRTUEDtDOPL
tdtFMSRtRTUEDtEDtLRTUOLtFMStDOPL
tdtFMSRLtFMStRTLEDtDOP
tdtFMSRtRTLEDtEDtLRTLOLtFMStDOP
LOOE
kh
kh
kh
kh
kh
kh
kh
kh
,
1,
,
1,
,
1,
,
1,
3600
)()(),(),(,min,0max
3600
)(),(),(),(max)(),(,min,0max
3600
)(,min)(),(),(max,0min
3600
)(),(),(),(min)(),(max,0min
,,,,,
,,,,,,,,,
,,,,
,,,,,,,,
,,,
For all resources except NGRs, the Optimal Energy is the sum of Overlapping and Non-overlapping Optimal Energy as follows:
ECATIEHPDNGR
khmikhmikhmi
fhmifhmifhmi
SSSSi
RTDmNOEOOEOE
FMMmNOEOOEOE
,,,,,,,,,
,,,,,,,,,
For NGRs, the Optimal Energy is the sum of Overlapping and Non-overlapping Optimal Energy as follows:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-101
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
NGR
khmikhmikhmikhmikhmi
fhmifhmifhmifhmifhmi
Si
RTDmLNOEGNOELOOEGOOEOE
FMMmLNOEGNOELOOEGOOEOE
,,,,,,,,,,,,,,,
,,,,,,,,,,,,,,,
C.2.1.1.23 RMR Energy
The calculation of RMR energy is not dependent and/or related to any other Expected Energy calculation. It is calculated to
fulfill the RMR contractual settlement requirement. It is calculated as the total energy under the RMR MW, which is calculated
as it follows,
Based on the MPM process, the RMR MW level will be determined per RMR resource (including condition 1 and condition 2)
for a given time in the following three steps,
Step 1,
If RT RMR Requirement <> 0 Then
DOPMWRMR _
Else If DA RMR Requirement <> 0 Then
),_,_,_min(max_ DOPcommitmentSTUCcommitmentRUCcommitmentIFMMWRMR
End If
Step 2,
CAISO Business Practice Manual BPM for Market Operations
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
If there exists RMR Exceptional Dispatch Instruction other than RMRS Then
)_,__max(_ MWRMRDispatchlExceptionaRMRMWRMR
Else if RMR Exceptional Dispatch Instruction is “RMRS” Then
If RMR instruction is a “MAX” instruction Then
Indicating that this resource is the original RMR resource being substituted
RMR_MW should be increased for RMR energy calculation
)___(__ DispatchlExceptionaRMRCommitmentIFMMWRMRMWRMR
Else -- This is the substituting resources
-- RMR_MW should be decreased for RMR energy calculation
)___(__ CommitmentIFMDispatchlExceptionaRMRMWRMRMWRMR
End If
End If
Step 3,
)_,min(_ MWRMRMNDCMWRMR
Where:
RMR_MW is the RMR MW level used in RMR energy calculation (time variant because it is tied to the DOP);
RT RMR Requirement The RMR requirement MW determined by Real-Time MPM process. (15-minute);
CAISO Business Practice Manual BPM for Market Operations
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Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
DA RMR Requirement The RMR requirement MW determined by Day-Ahead MPM process. (hourly);
IFM_Commitment BINDING commitment schedule MW from IFM. Assume zero if none exists (hourly);
RUC_Commitment BINDING commitment schedule MW from RUC. Assume zero if none exists (hourly);
STUC_Commitment BINDING commitment schedule MW from RTM through the short term unit commitment
process. Assume zero if non exists (15 minute);
DOP Dispatch Operating Point from RTM;
RMR Exceptional Dispatch The Exceptional Dispatch MW when the Exceptional Dispatch Energy code is one of the
four types: “RMRR”, “RMRS”, “RMRT”, “RMRV” – This can be simplified as essentially all Exceptional
Dispatch Energy code beginning with the letters “RMR”;
PreviousDOT Dispatch Operating Target (MW) for the previous 5-minute interval from RTM (5-minute);
MNDC RMR Contractual Capacity defined in MF for RMR resources. It can be less or equal to the Pmax;
C.2.1.1.24 EE treatment for EIM resources
1. Calculate BASE energy for all EIM resources: EIMhihi SiBSEIMBASE hr 1,,
2. For participating EIM resources, calculate real-time EE as indicated in the above sections C.2.1.1.7 through C.2.1.1.23,
except replace the following terms:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-104
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
a. Replace DAS with BSEIM, i.e. all RT energy is relative to the BASE schedule. EIM resources do not directly
participate in the DA market, thus do not have a DAS.
b. Replace ED with MD.
3. For non-participating EIM resources, calculation of real-time EE is simplified. Calculate as follows:
a. EIMNPRhihihmi SiBSEIMFMMOE FMMm 12/)( ,,,,
b. EIMNPRhmBNDihihihmi SiexiststMDFMMDOTMDE RTDm)( 12/)( ,,,,,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-105
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5t Expected energy for an EIM Participating Resource. EIMPR
Si
DAS
DOP
FMS
IIE15(+)
IIE5(+)
BASE(+)
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-106
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Figure 5u Expected energy for an EIM non-participating resource with MDE. EIMNPR
Si
C.2.1.2 Total Expected Energy
kh
kh
T
T
ikhi td
tDOPTEE
,
1,3600
)(,,
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-107
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
C.2.1.3 Ramping Dispatch Operating Target
lll
ll
llli TtTTt
TT
DOTDOTDOTtRDOT
11
1
11)(
C.2.1.4 Total Target Expected Energy
kh
kh
T
T
ikhi td
tRDOTTTEE
,
1,3600
)(,,
C.2.1.5 Ramping Tolerance
khikhikhi TEETTEERAMPT ,,,,,,
C.2.1.6 Exceptional Dispatch Energy and Its Pricing
In expected energy allocation, the bid prices used for Exceptional Dispatch Energy will be based on CAISO tariff section 11.5.6
depending on the individual Exceptional Dispatch Instruction type. Furthermore, after the appropriate Energy Bid prices are
allocated, the Exceptional Dispatch Energy determined by the extended Exceptional Dispatch Instruction as described in
C2.1.1.15 will be re-classified as Optimal Energy with its Bid prices determined by Exceptional Dispatch rules.
C.2.1.7 Energy Type Legend
CAISO uses the following legend to identify the different types of Energy:
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-108
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-109
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
C.2.1.8 General Imbalance Energy Calculation Rules
Following rules apply to all Dynamic System Resources that are not MSS Load Following and not System Resources.
Following are the main rules,
Energy types with the same sign stack up; they do not overlap
Energy types with opposite signs overlap
Standard Ramping Energy is always present and it may overlap with DA Schedule Energy
Ramping Energy Deviation may only overlap with Standard Ramping Energy and/or DA Schedule Energy
Residual Energy may only overlap with DA Schedule Energy
Optimal and Exceptional Dispatch Energy do not overlap with each other, but they may overlap with DA Schedule Energy.
Note: for illustration purposes, only energy from Day-Ahead and Real-Time Dispatch schedules are shown. Assume
Fifteen-Minute Market Schedules equal Real-Time Dispatch.
Exhibit D-1 illustrates the DA Energy breakdown. It assumes that there is a DA Self-Schedule and Energy Bid for the
corresponding resource. It also assumes that the resource has a non-zero Pmin.
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-110
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Exhibit C-1: Day-ahead Energy Breakdown
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW Day-ahead Scheduled Energy
Day-ahead Bid Awarded Energy
Day-ahead Self-Scheduled Energy
Day-ahead Minimum Load Energy
Day-ahead LEL
Pmin
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-111
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Exhibit C-2: Standard Ramping Energy and Ramping Energy Deviation (with ramping deviation caused by slower ramp)
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-112
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Exhibit C-3: Ramping Energy Deviation (Changing Ramp Rate)
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-113
Formatted: Font: 8 pt, Not Italic
Formatted: Font: 8 pt, Not Italic
Exhibit C-4: Ramping Deviation (Startup & Shutdown)
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
CAISO Business Practice Manual BPM for Market Operations
Version 41Version 38Version42 Last Revised: June 2, 2015January 6, 2014January 6, 2014September 30, 2014, Page C-114
Formatted: Font: 8 pt, Not Italic
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Exhibit D-5 shows an economic Dispatch that generates a DOP curve ramping first up towards the current hour, ramp down
below the DA Schedule in the middle of hour, then ramp further down below the Day-Ahead Schedule in the following hour.
This dispatch pattern results in the following Expected Energy: Day-Ahead Schedule Energy, Standard Ramping Energy,
Ramping Energy Deviation, Optimal Energy, Residual Imbalance Energy.
Exhibit C-5: Comprehensive Economic Dispatch Case 1
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
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Exhibit D-6 shows an economic dispatch that generates a DOP curve ramping first up towards the current hour however below
Day-Ahead Schedule, further ramp up above the Day-Ahead Schedule in the middle of hour, then ramp further down but above
the Day-Ahead Schedule in the following hour. This dispatch pattern results in the following Expected Energy: Day-Ahead
Schedule Energy, Standard Ramping Energy, Ramping Energy Deviation, Optimal Energy, Residual Imbalance Energy.
Exhibit C-6: Comprehensive Economic Dispatch Case 2
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
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Exhibit D-7 shows an economic Dispatch that generates a DOP curve ramping first down towards the current hour however
above Day-Ahead Schedule, further ramp down below the Day-Ahead Schedule in the middle of hour, then ramp further up but
below the Day-Ahead Schedule in the following hour. This dispatch pattern results in the following Expected Energy: Day-
Ahead Schedule Energy, Standard Ramping Energy, Ramping Energy Deviation, Optimal Energy, Residual Imbalance Energy.
Exhibit C-7: Comprehensive Economic Dispatch Case 3
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
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Exhibit D-8 shows the impact of Exceptional Dispatch. The DOP curve ramps first up towards the current hour, ramp down
below the Day-Ahead Schedule in the middle of hour, then ramp further down below the Day-Ahead Schedule in the following
hour. This dispatch pattern results in the following Expected Energy: Day-Ahead Schedule energy, standard ramping energy,
ramping energy deviation, Optimal Energy, Residual Imbalance Energy and Exceptional Dispatch Energy.
Exceptional Dispatch energy is either Incremental energy above the RT LMP MW and below the lower of the DOP or the
Exceptional Dispatch instruction; or Decremental energy below the RT LMP MW and above the higher of the DOP or the
Exceptional Dispatch instruction.
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Exhibit C-8: Comprehensive Exceptional Dispatch Case 1
Exhibit D-9 shows an Exceptional Dispatch that generates a DOP curve ramping first up towards the current hour however
below Day-Ahead Schedule, further ramp up above the Day-Ahead Schedule in the middle of hour, then ramp further down
but above the Day-Ahead Schedule in the following hour. This dispatch pattern results in the following Expected Energy:
Day-Ahead Schedule Energy, Standard Ramping Energy, Ramping Energy Deviation, Optimal Energy, Residual Imbalance
Energy and Exceptional Dispatch Energy.
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
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Exhibit C-9: Comprehensive Exceptional Dispatch Case 2
Exhibit D-10 takes the original example from D-9 and shows the impact of a SLIC derate/rerate. In D-10, it assumes a
SLIC derate of Pmax between min 0’ to 27.5’ in current hour and a SLIC rerate of Pmin between 0’ and 15’ in the next hour.
This causes negative derate energy and positive derate energy in the corresponding time period.
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
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Exhibit C-10: Impact of SLIC derate/rerate (Derate Energy)
C.2.1.9 Expected Energy in Pumping Mode
Following rules apply to all Pumped-Storage Hydro Resource in pumping mode and Pump resources (Participating Load). For
such resources, the possible Expected Energy generated under zero can be DA Pumping Energy, RT Pumping Energy,
Standard Ramping Energy and Ramping Energy Deviation
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
Negative Derate Energy
RTUOL: Derated Pmax
RTLOL: Rerated Pmin
Positive Derate Energy
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DA Pumping Energy is always negative and there is no further breakdown of DA Pumping Energy
RT Pumping Energy can be positive or negative
Standard Ramping Energy and Ramping Energy Deviation follow the same rules described in D.3.1.3
DA and RT Pumping Energy can overlap each other
Even though there can be HASP Intertie Schedule or Exceptional Dispatch equal or below zero, corresponding
Imbalance Energy is always accounted for as RT Pumping Energy
Note: for illustration purposes, only energy from Day-Ahead and Real-Time Dispatch schedules are shown. Assume Fifteen-
Minute Market Schedules equal Real-Time Dispatch.
Exhibit D-11 shows a case that a Pump resource has been committed in DA pumping mode and get dispatched in Real-Time in
Pumping mode for the current hour. It also assumes the resource is off-line for the previous and next hour. In this case, the
Expected Energy generated include DA pumping energy, Standard Ramping Energy and Ramping Energy Deviation.
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Exhibit C-11: Day-ahead Pumping Energy
Exhibit D-12 shows a case that a Pump resource has been committed in DA pumping mode and then committed off-line in
Real-Time. A DOP being zero had been dispatched. It also assumes the resource is off-line for the previous and next hour.
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW Day-ahead Pumping Energy
Zero MW
Zero MW
Standard Ramping Energy overlapped with Ramping Energy Deviation.
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In this case, the Expected Energy generated include DA pumping energy (negative), Real-time pumping energy (positive),
Standard Ramping Energy and Ramping Energy Deviation
Exhibit C-12: Positive Real-time Pumping Energy
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW Negative Day-ahead Pumping Energy
Zero MW
Zero MW
Standard Ramping Energy overlapped with Ramping Energy Deviation.
Positive Real-time Pumping Energy
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Exhibit D-13 shows a case that a Pump resource has not been committed in DA (offline mode) and then committed on-line
in Real-Time. A DOP below zero had been dispatched and a vertical curve is used for startup and shutdown. It also
assumes the resource is off-line for the previous and next hour. In this case, the Expected Energy generated includes Real-
time pumping energy (negative).
Exhibit C-13: Negative Real-time Pumping Energy
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW Real-time Pumping Energy
Zero MW
Zero MW
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Exhibit D-14 shows a case that a Pumped-Storage Hydro (PSH) Resource has been committed in DA generation mode and
then committed in pumping mode in Real-Time. A DOP below zero had been dispatched and a vertical curve is used for startup
and shutdown. It also assumes that the resource is off-line for the previous and next hour. In this case, the Expected Energy
generated includes Day-Ahead Scheduled energy, Negative Optimal Energy and Negative Real-time Pumping Energy. The
energy above zero MW uses the same rules described in D 3.1.3.
Exhibit C-14: PSH from DA generation mode to Real-time pumping mode
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW Negative Real-time Pumping Energy
Zero MW
Zero MW
DA Scheduled Energy, which may also further break down into DA Bid Award Energy, DA self-scheduled Energy and DA Minimum Load Energy.
Negative Optimal Energy, which overlaps the Day-Ahead Scheduled energy.
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Exhibit D-15 shows a case that a Pumped-Storage Hydro (PSH) Resource has been committed in DA pumping mode and then
committed in generation mode in Real-Time. In this case, the Expected Energy generated includes negative DA Pumping
Energy, positive Optimal Energy and positive Real-Time Pumping Energy and Real-Time Minimum Load Energy. The energy
above zero MW uses the same rules described in D 3.1.3.
Exhibit C-15: PSH from DA pumping mode to RT generation mode
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW DA Pumping Energy
Zero MW
Zero MW
Positive Optimal Energy
Real-time Minimum Load Energy
Pmin Pmin
Positive RT Pumping Energy, which overlaps the DA Pumping Energy.
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C.2.1.10 Block Accounting in Expected Energy
When calculating Expected Energy for System Resources(hourly pre-dispatched or not) and Non-Dynamic Resource-Specific
System Resources, the block accounting method is deployed. The block accounting method uses a step function at the
relevant DOT as the converted “block DOP” when calculating the Expected Energy under the curve. It is important to note that,
after the application of the “block DOP”, all other Expected Energy calculation rules are the same as other resources. Exhibit
16 takes D-6 as the original example and apply the block accounting method to the DOP, it resolves in the converted DOP
curve (indicated by the pink dotted line). Notice that, while all Expected Energy calculation principle stays the same, the
Expected Energy for each interval is different now under the “block DOP” from the Expected Energy under the original DOP
(dispatched from ADS).
Note: for illustration purposes, only energy from Day-Ahead and Real-Time Dispatch schedules are shown. Assume Fifteen-
Minute Market Schedules equal Real-Time Dispatch.
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Exhibit C-16: Expected Energy under the block accounting method (Non HPD Tie)
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
“Block DOP Curve”
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C.2.1.11 MSS Load Following Energy
MSS Load Following Energy (MSSLFE) is the area between the Load Following Instruction and the Day-Ahead Schedule.
Optimal and Exceptional Dispatch Energy do not overlap with each other, but they may overlap with Day-Ahead Scheduled
Energy and/or MSS Load Following Energy. An important point to indicate is that, all MSS load following instructions mentioned
here are the qualified MSS load following instructions. The data flow for these instructions is as it follows,
Step 1: MSS MPs send in the MSS load following instructions through ADS API on a 5-minute or hourly base;
Step 2: ADS will publish these instructions to RTN through interval web services;
Step 3: RTN will evaluate these instructions and apply appropriate adjustments if necessary. This results in the qualified MSS
load following instructions. RTN further uses these qualified instructions in its dispatch for the MSS load following resources.
Dispatch Instructions are sent to MSS MPs through ADS which includes the qualified instructions as part of the DOT
breakdown;
Step 4: MQS will use the qualified MSS load following instructions in clarification of Expected Energy for MSS load following
resources.
D-18 takes the comprehensive economic Dispatch case in D-5 and adds in the MSS Load Following Instructions. Because of
the MSS Load Following Instructions, the clarifications of Expected Energy do change now.
D-18 illustrates the following cases:
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1. Between interval 45’ and 52.5’ in the previous hour, there is positive MSS Load Following energy incurred due to the MSS
load following up instructions. Since the economic dispatches “agree” with the load following up, there is further positive
Optimal Energy incurred, but however there is no overlapping between Optimal Energy and MSS Load Following Energy.
Between interval 50’ to 52.5’, it is also important to note that, standard ramping takes precedence over MSS Load Following
Energy. They do not overlap each other;
2. Between interval 0’ and 30’ in the current hour, similar to item 1, the MSS load following up instructions “agree” with the
economic Dispatches, hence both positive Optimal Energy and MSS Load Following Energy are incurred and they do not
overlap. Between interval 27.5’ to 30’, there is a small triangle above the DOP that shows the overlapping between positive
MSS Load Following Energy and negative Optimal Energy. This is caused by the ramping down case in which the dispatches
“disagree” with the MSS load following up instructions;
3. Between interval 30’ and 50’ in the current hour, there are three Expected Energy related to the topic of MSS load following:
3.1. Triangle area (between 30’ and 32.5’) below DOP and above Day-Ahead Schedule is clarified as positive Optimal Energy.
The reason is because it is incremental Energy above Day-Ahead Schedule and we deem that having no relationship to the
MSS load following down instruction;
3.2. Area (between 32.5’ and 0’) below the DOP and standard ramp curve AND above the DOP and MSS load following down
instruction is clarified as MSS Load Following Energy. It is not overlapping with any other Expected Energy. The reason is that,
that decremental Energy is deemed to be solely caused by the MSS load following down instructions. Furthermore, the
standard ramping area is not affected since standard ramping takes precedence over MSS Load Following Energy;
3.3. Area (between 30’ and 50’) below the DOP and Day-Ahead Schedule AND above the MSS load following down instruction
is clarified as Negative MSS Load Following Energy overlapping with positive Optimal Energy. The reason is that, the dispatch
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“disagrees” with the MSS load following down instruction. Without the economic reason, the DOP would have been at the MSS
load following down instruction level. It is brought up because more economic Energy in Real-Time is needed and hence a
positive Optimal Energy is incurred in that area.
4. Between 2.5’ and 15’ in the next hour, the area above Day-Ahead Schedule and standard ramp curve AND below the MSS
load following up instruction is clarified as positive MSS Load Following Energy overlapping with negative Optimal Energy. The
reason is that, the economic Dispatch “disagree” with the MSS load following up and hence an additional negative Optimal
Energy is generated.
Note: for illustration purposes, only energy from Day-Ahead and Real-Time Dispatch schedules are shown. Assume Fifteen-
Minute Market Schedules equal Real-Time Dispatch.
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Exhibit C-18: MSS Load Following Energy (Economic Dispatch with MSSLF case 1)
D-19 takes the comprehensive economic dispatch case in D-6 and adds in the MSS Load Following Instructions. Because of
the MSS Load Following Instructions, the clarifications of Expected Energy do change now. As it is shown, the overlapping and
non-overlapping cases related MSS Load Following Energy follow the same principle as it is described for D-18.
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW Positive MSS Load Following energy. No overlapping.
Positive MSS Load Following energy overlapping with Negative Optimal Energy
Negative MSS Load Following energy
Overlapping with positive Optimal Energy
Only positive Optimal Energy. No overlapping.
Positive MSS Load Following energy overlapping with negative Optimal Energy
Positive MSS Load Following energy. No overlapping.
Negative MSS Load Following Energy. No overlapping.
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Exhibit C-19: MSS Load Following Energy (Economic Dispatch with MSSLF case 2)
D-20 takes the comprehensive economic dispatch with MSSLF case in D-18 and adds in the Exceptional Dispatch Instructions.
Again, when Exceptional Dispatch Instruction “agrees” with the MSS load following instruction, the MSS Load Following Energy
does not overlap with Exceptional Dispatch Energy. When they “disagree”, there is a potential of overlapping. Area (between
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
Positive MSS Load Following energy. No overlapping.
Positive MSS Load Following energy overlapping with negative Optimal Energy
Negative MSS Load Following energy overlapping with positive Optimal Energy
Positive MSS Load Following energy overlapping with negative Optimal Energy
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interval 30’ and interval 47.5’ in current hour) below the Exceptional Dispatch and above the LMP MW is clarified as negative
MSS Load Following Energy overlapping with the positive Exceptional Dispatch Energy. It is important to note that, there are
cases that MSSLF instruction “disagree” with Exceptional Dispatch, however, there is no overlapping between MSS Load
Following Energy and Exceptional Dispatch Energy because the overlapping case is taken care by Optimal Energy. Area
between 0’ and 15’ in the next hour illustrates this case.
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW Positive MSS Load Following energy. No overlapping.
Positive MSS Load Following energy overlapping with Negative optimal energy
Negative MSS Load Following energy
Overlapping with positive Optimal Energy
Only positive optimal energy. No overlapping.
Positive MSS Load Following energy overlapping with negative Optimal Energy
Positive MSS Load Following energy. No overlapping.
Negative MSS Load Following Energy. No overlapping.
Negative MSS Load Following energy overlapping with positive Exceptional Dispatch Energy
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Exhibit C-20: MSS Load Following Energy (D-18 with Exceptional Dispatch)
D-21 takes the comprehensive economic dispatch with MSSLF case in D-19 and adds in the Exceptional Dispatch Instructions.
In this example, the Exceptional Dispatch Instructions do not change the MSS Load Following Energy. There are intervals in
which Exceptional Dispatch Instructions “disagree” with Exceptional Dispatch Instructions, however, it is already accounted for
by Optimal Energy. Area between interval 45’ and 0’ in previous hour, interval 0’ and 57.5 in current hour illustrates such cases.
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Exhibit C-21: MSS Load Following Energy (D-19 with Exceptional Dispatch)
C.2.1.12 RMR Energy
D-22 Illustrates an example in which the “RMR DOP” is calculated based on the combination of DA, RT RMR requirements, DA
and STUC commitment schedules and the DOP. The “RMR DOP” is really a curve representing what we believe is dispatch
under the RMR contractual obligation. The RMR energy is simply the area under the “RMR DOP” curve. RMR energy is the
energy CAISO will pay based on RMR contract, not based on the market.
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
Positive MSS Load Following energy. No overlapping.
Positive MSS Load Following energy overlapping with negative Optimal Energy
Negative MSS Load Following energy overlapping with positive Optimal Energy
Positive MSS Load Following energy overlapping with negative Optimal Energy
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In D-22, Several cases are illustrated,
Case 1: Interval (45’ to 0’ for the previous hour)
We have RT RMR requirement and hence the “RMR DOP” is the same as the DOP for those three intervals;
Case 2: Interval (0’ to 15’ for the current hour)
There is no RT RMR requirement. There is DA RMR requirement which is equal to the DA commitment schedule. We also
have STUC commitment schedule equal to the LMP MW. In this case, the “RMR DOP” is still the same as the DOP for those
three intervals according to our algorithm;
Case 3: Interval (15’ to 30’ for the current hour)
There is no RT RMR requirement. There is DA RMR requirement which is equal to the DA commitment schedule. There is no
STUC commitment schedule. According to our algorithm, the “RMR DOP” is equal to the Day-Ahead Schedule;
Case 4: Interval (30’ to 0’ for the current hour)
There is no RT RMR requirement. There is DA RMR requirement which is equal to the DA commitment schedule. There is a
STUC commitment schedule equal to the LMP MW. According to our algorithm, this leads to a “RMR DOP” which mostly
simulate the DOP curve except in the interval (30’ to 32.5’) since the STUC commitment schedule is lower than the DOP;
Case 4: Interval (0’ to 15’ for the next hour)
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There is no RT RMR requirement. There is DA RMR requirement which is equal to the DA commitment schedule. There is a
STUC commitment schedule equal to the LMP MW. According to our algorithm, this leads to a “RMR DOP” which mostly
simulate the DOP curve except in the interval (0’ to 2.5’) since the STUC commitment schedule is lower than the DOP;
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Note: for illustration purposes, only energy from Day-Ahead and Real-Time Dispatch schedules are shown. Assume Fifteen-
Minute Market Schedules equal Real-Time Dispatch.
Exhibit C-22: “RMR DOP” curve calculation and RMR energy
45'
50'
55'
0' 5' 10'
15'
20'
25'
30'
35'
40'
45'
50'
55'
0' 5' 10'
15'
MW
Real-time RMR requirement
RMR DOP DA RMR Requirement AND DA Commitment Schedule
STUC Commitment
STUC Commitment
RMR DOP
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C.3 Ex Post Capacity Allocation
This section describes the ex post capacity allocation of various services onto a Generating Unit
Energy Bid and capacity range for the purpose of indexing Instructed Imbalance Energy (IIE)
out of these services onto Energy Bid. The capacity allocation rules are consistent with the ones
employed in the RTM applications.
The main output of this process is to come up with the following capacity range per market
resource and Dispatch Interval,
SRC Spinning Reserve allocated capacity range.
NSC
MEC
DAEC
DeRatedCAP
Non-Spinning Reserve allocated capacity range.
Real-time Optimal Energy Capacity range
Day-ahead Optimal Energy Capacity range
Derated Capacity Range
The following notation is used in the following Sections:
LOL Lower operating limit; it is the minimum load incorporating overrates,
which includes the late SLIC. MQS gets the original value from RTM and
then applies late SLIC if applicable.
UOL
UOL(rtm)
Upper operating limit; it is the maximum capacity incorporating derates,
which includes the late SLIC. MQS gets the original value from RTM and
then apply late SLIC if applicable.
Upper operating limit; it is the maximum capacity incorporating derates
in RTM if applicable in time. MQS gets this from RTM.
LRL Lower regulating limit.
URL Upper regulating limit.
LEL Lower economic limit; it is the starting operating level of the Real-Time
Energy Bid.
UEL Upper economic limit; it is the ending operating level of the Real-Time
Energy Bid.
LFD Load Following Down qualified self-provision capacity.
(If exists in RT, take RT, otherwise take DA. In other words, they are not
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incremental like AS. Hourly for DA and 15-minute for RT)
LFU
LFI
Load Following Up qualified self-provision capacity.
(If exists in RT, take RT, otherwise take DA. Hourly for DA and 15-
minute for RT)
Validated Load Following Instructions (5 minute based. This value is a
part of the DOT breakdown from RTM.).
RD Regulation Down award; it includes qualified self-provision capacity.
(DA + RT. RTM has this total already)
RU Regulation Up award; it includes qualified self-provision capacity.
(DA + RT. RTM has this total already)
SR Spinning Reserve award; it includes qualified self-provision capacity.
(DA + RT. RTM has this total already)
NS Non-Spinning Reserve award; it includes qualified self-provision
capacity.
(DA + RT. RTM has this total already)
LFDC Load Following Down allocated capacity.
LFUC Load Following Up allocated capacity.
RDC Regulation Down allocated capacity.
RUC Regulation Up allocated capacity.
SRC Spinning Reserve allocated capacity range.
NSC
MEC
DAEC
DeRatedCAP
MinExCap
MaxExCap
Non-Spinning Reserve allocated capacity range.
Real-time Optimal Energy Capacity range
Day-ahead Optimal Energy Capacity range
Derated Capacity Range
Minimum Ex-post Capacity
Maximum Ex-post Capacity
The Generating Unit is considered online if the RTUC status is “ON” in the relevant Dispatch
Interval and offline if the commitment status is “OFF”. The Generating Unit is considered on
Regulation if the RTM regulating status is “ON” in the relevant Dispatch Interval, and off
Regulation if the regulating status is “OFF”. The lower and upper regulating limits are used
when the Generating Unit is on Regulation and they are equally or more restrictive than the
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lower and upper operating limits, unless the latter are modified by derates. The Energy Bid
range is restricted between the Minimum Load and the maximum capacity, but it may extend
beyond the regulating limits, and also beyond the operating limits if they are derated.
Derate Capacity:
When considering late SLIC case in the ex-post capacity calculation, it is possible that the
adjusted UOL is lower than the DOP. This situation reflect the fact that Real-Time dispatch
algorithm does not know and hence account for this derate so the DOP is higher than what the
unit can physically deliver.
In such cases, we never change the Expected Energy calculation. All Expected Energy will be
calculated in the same way according to the DOP. What get affected is the energy allocation
because now we have a portion of the Expected Energy that will not have a capacity range that
corresponds to.
The capacity “Derate Capacity” is used to solve this problem. Any capacity range above the
Spin range to the DOP will be categorized as “Derate Capacity”. The allocation logic is exactly
the same as any other capacity range. The market service type will be filled with “Derate
Capacity” in this case.
Notice that, there can be late SLIC for Pmin as well. In such cases, while the late SLIC does
affect the after the fact calculated LOL and hence “push up” the Optimal Energy, Non-spin and
Spin capacity, there is no need to introduce a new service type because the capacity
underneath the ME is covered by “Day-Ahead energy capacity”.
C.3.1.1 Online Resource not on Load Following or Regulation
In this case, the capacity allocation is as follows:
Spinning Reserve is allocated first from the lower of the upper economic limit or the
upper operating limit, and until the higher of the lower economic limit or the lower
operating limit.
Non-Spinning Reserve is allocated next below the Spinning Reserve and until the higher
of the lower economic limit or the lower operating limit.
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In mathematical terms:
0)MaxExCap), - (UOL(rtm) Max(
)0,max(
)0,,max(min
,min
,min
,max
DeRatedCap
MinExCapDAEC
NSCSRCMinExCapMaxExCapMEC
SRCMinExCapMaxExCapNSNSC
MinExCapMaxExCapSRSRC
UELUOLMaxExCap
LELLOLMinExCap
Exhibit D-23 illustrates a typical scenario under this case.
Exhibit D-23: Online Resource not on Load Following or Regulation
C.3.1.2 Online Resource not on Load Following, but on Regulation
In this case, the capacity allocation is as follows:
Regulation Up and Regulation Down are allocated first and pro rata between the most
restrictive of the regulating or operating limits. No Energy Bid is required for Regulation.
Spinning Reserve is allocated next below the Regulation Up and the upper economic
limit, and until the Regulation Down or the lower economic limit.
MW
$/MWh SRC NSC
max(LOL, LEL) min(UOL, UEL)
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Non-Spinning Reserve is allocated next below the Spinning Reserve and until the
Regulation Down or the lower operating limit.
In mathematical terms:
0)MaxExCap), - (UOL(rtm) Max(
)0,max(
)0,,max(min
,min
,,maxmax
,,minmin
,max,min,min
,max,min,min
DeRatedCap
MinExCapDAEC
NSCSRCMinExCapMaxExCapMEC
SRCMinExCapMaxExCapNSNSC
MinExCapMaxExCapSRSRC
LELRDCLRLLOLMinExCap
UELRUCURLUOLMaxExCap
LRLLOLURLUOLRURD
RURURUC
LRLLOLURLUOLRURD
RDRDRDC
Exhibit D-24 illustrates a typical scenario under this case.
Exhibit C-24: Online Resource not on Load Following but on Regulation
MW
$/MWh SRC RUC NSC RDC
max(LOL, LRL) min(UOL, URL) UEL LEL
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C.3.1.3 Online Resource on Load Following, Not on Regulation
In this case, the capacity allocation is as follows:
Load following up and Load following down are allocated first and pro rata between the
most restrictive of the economic or operating limits. An Energy Bid is required for Load
Following.
Spinning Reserve is allocated next below the Load following up and until the Load
following down.
Non-Spinning Reserve is allocated next below the Spinning Reserve and until the Load
following down.
In mathematical terms:
0)MaxExCap), - (UOL(rtm) Max(
)0,max(
)0,,max(min
,min
,max
,min
),max,min,min,0max(
),max,min,min,0max(
DeRatedCap
MinExCapDAEC
NSCSRCMinExCapMaxExCapMEC
SRCMinExCapMaxExCapNSNSC
MinExCapMaxExCapSRSRC
LFDCLELLOLMinExCap
LFUCUELUOLMaxExCap
LFILELLOLUELUOLLFULFD
LFULFULFUC
LELLOLUELUOLLFULFD
LFDLFDLFILFDC
Exhibit D-25 illustrates a typical scenario under this case.
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Exhibit D-25: Online Resource on Load Following, but not on Regulation
C.3.1.4 Online Resource on Load Following & Regulation
In this case, the capacity allocation is as follows:
Load following up and Load following down are allocated first and pro rata between the
most restrictive of the economic, regulating, or operating limits. An Energy Bid is
required for Load Following.
Regulation Up and Regulation Down are allocated next and pro rata below and above
Load following up and Load following down, respectively. In this case, the Energy Bid
covers Regulation.
Spinning Reserve is allocated next below the Regulation Up and until the Regulation
Down.
Non-Spinning Reserve is allocated next below the Spinning Reserve and until the
Regulation Down.
In mathematical terms:
MW
$/MWh LFUC SRC LFDC NSC
max(LOL, LEL) min(UOL, UEL)
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0)MaxExCap), - (UOL(rtm) Max(
)0,max(
)0,,max(min
,min
,,max
,,min
,,max,,min,min
,,max,,min,min
),,max,,min,min,0max(
),,max,,min,min,0max(
DeRatedCap
MinExCapDAEC
NSCSRCMinExCapMaxExCapMEC
SRCMinExCapMaxExCapNSNSC
MinExCapMaxExCapSRSRC
RDCLFDCLELLRLLOLMinExCap
RUCLFUCUELURLUOLMaxExCap
LFUCLFDC
LELLRLLOLUELURLUOL
RURD
RURURUC
LFUCLFDC
LELLRLLOLUELURLUOL
RURD
RDRDRDC
LFILELLRLLOLUELURLUOLLFULFD
LFULFULFUC
LELLRLLOLUELURLUOLLFULFD
LFDLFDLFILFDC
Exhibit D-26 illustrates a typical scenario under this case.
Exhibit C-26: Online Resource on Load Following and Regulation
MW
$/MWh LFUC SRC RUC LFDC NSC RDC
max(LOL, LRL, LEL) min(UOL, URL, UEL)
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C.4 Expected Energy Allocation
In order to support various compliance and settlement functions, we will need a combined
break-down of various market services, Expected Energy and Day-Ahead/Real-Time Energy
Bid curve. This break-down list is the so-called “Expected Energy Allocation”.
The breakdown will look like the following and each unique combination of Expected Energy
type, market service type and the corresponding bid segment will uniquely determines one
unique energy amount.
Expected Energy
Type
Market Service
Type
Bid Price Energy
Expected Energy Types
What the market offers that has relationship to settlement bid cost recovery and compliance
Corresponding Price with matched bid segment
Break-down energy amount
C.4.1. Expected Energy Types and Market Service Types
In MRTU, the market service types simply represent the various commodities supported by the
market that has relationship to Settlement Bid Cost Recovery and compliance calculation.
These market service types breakdown is corresponding to the capacity range derived from the
ex-post capacity allocation described in D.4
The reason that derate capacity, market energy capacity and day-ahead energy capacity are
calculated is to determine spinning reserve and non-spinning reserve capacity because those
capacities do affect the ex-post spin and non-spin capacity range. The expected energy within
the capacity range of spinning reserve and non-spinning reserve capacities are also referred
“spin energy” and “non-spin energy” and used in Compliance for Spin and non-spin No Pay.
Market Service types are only used by Compliance for spin and non-spin “no pay” calculations.
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They are as it follows,
SR Spinning Reserve Capacity range.
NR
ME
DAC
DEC
Non-Spinning Reserve Capacity range.
Market Energy Capacity
Day-ahead Capacity
Derated Capacity
Market Participants will be able to review all Expected Energy Categories in OASIS and CMRI.
All energy types can be verified against the Market Participant’s settlements statements to
validate both Day Ahead HASP and Real Time Charge Codes. The following matrix outlines
how each report shall display the various types of Energy Types. Note that for the definition of
the Exceptional Dispatch types, please refer Settlements and Billing BPM for CC6470 –
Instructed Imbalance Energy Settlement.
Expected Energy Category
OASIS CMRI – Expected Energy
CMRI – Expected Energy Allocation Details
Day Ahead Scheduled Energy
DASE DASE DASE
Day Ahead Bid Awarded Energy
DABE DABE n/a
Day Ahead Self Schedule Energy
DSSE DSSE n/a
Day Ahead Minimum Load Energy
DMLE DMLE n/a
Day Ahead Pumping Energy
DAPE DAPE n/a
Base Schedule Energy
BASE BASE BASE
Total Expected Energy
TEE TEE n/a
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Optimal Energy1 OE OE OE
Standard Ramping Energy
SRE SRE SRE
Ramping Energy Deviation
RED RED RED
RMR Energy RMRE RMRE n/a
Residual Energy RE RE RE
Minimum Load Energy1
MLE MLE MLE
Pumping Energy1 PE PE n/a
Real Time Self Scheduled Energy
RTSSE RTSSE RTSSE
SLIC Energy1 SE SE SE
MSS Load Following Energy
MSSLFE MSSLFE MSSLFE
Exceptional Dispatch Energy1
TMODEL EDE TMODEL
Exceptional Dispatch Energy -TMODEL 11
TMODEL1
EDE TMODEL1
Exceptional Dispatch Energy – TMODEL21
TMODEL2
EDE TMODEL2
Exceptional Dispatch Energy – TMODEL31
TMODEL3
EDE TMODEL3
Exceptional Dispatch Energy – TMODEL41
TMODEL4
EDE TMODEL4
Exceptional Dispatch Energy – TMODEL51
TMODEL5
EDE TMODEL5
Exceptional Dispatch Energy – TMODEL61
TMODEL6
EDE TMODEL6
Exceptional Dispatch Energy – TMODEL71
TMODEL7
EDE TMODEL7
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Exceptional Dispatch Energy - SYSEMR1
SYSEMR
EDE SYSEMR
Exceptional Dispatch Energy – SYSEMR11
SYSEMR1
EDE SYSEMR1
Exceptional Dispatch Energy - TEMR1
TEMR
EDE TEMR
Exceptional Dispatch Energy - RMRR1
RMRR
EDE RMRR
Exceptional Dispatch Energy - RMRS1
RMRS
EDE RMRS
Exceptional Dispatch Energy - RMRT1
RMRT
EDE RMRT
Exceptional Dispatch Energy - NonTModel1
NonTMod
EDE NonTMod
Exceptional Dispatch Energy – TORETC1
TORETC EDE TORETC
Exceptional Dispatch Energy – TORETC11
TORETC1
EDE TORETC1
Exceptional Dispatch Energy - ASTEST1
ASTEST
EDE ASTEST
Exceptional Dispatch Energy - TEST1
TEST
EDE TEST
Exceptional Dispatch Energy - VS1
VS
EDE VS
Exceptional Dispatch Energy - BS1
BS
EDE BS
Exceptional Dispatch Energy -
SLIC EDE SLIC
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SLIC1
Manual Dispatch Energy – BS1
MDE MDE PBS
Manual Dispatch Energy – NONTMOD1
MDE MDE PNONTMOD
Manual Dispatch Energy – SYSEMR1
MDE MDE PSYSEMR
Manual Dispatch Energy – TEMR1
MDE MDE PTEMR
Manual Dispatch Energy – TEST1
MDE MDE PTEST
Manual Dispatch Energy – TMODEL1
MDE MDE PTMODEL
Manual Dispatch Energy – VS1
MDE MDE PVS
RMRRC2 RMRRC2 EDE RMRRC2
OTHER OTHER EDE OTHER
1Separate allocations for 15 minute and 5-minute dispatches will be reported.
C5.2 Allocation Logic
There are two steps in this allocation:
Step 1: Ex-post Capacity Allocation for every market resource and 5 minute interval
This has been described in D4. The final result leads to the following table (hyperthetical data)
-- Example assumes no derate and hence no de-rated capacity exists.
Market Service Type MW range
Spinning Reserve Capacity 50 – 55MW
Spinning Reserve Capacity 45 – 50MW
Non Spinning Reserve Capacity 40 – 45MW
Non Spinning Reserve Capacity 30 – 40 MW
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Optimal Energy Capacity 20 – 30 MW
Day-ahead Energy Capacity 0 – 20 MW
Step 2: Stack up the table in the order that it is shown to the left of the Expected Energy curve and, apply the Real-Time Energy Bid segment to Real-Time Expected Energy AND the Day-Ahead Energy Bid segment to Day-Ahead Expected Energy
Per Expected Energy area, market service type, DA/RT Energy Bid segment, this breaks down
the Expected Energy area into further detail and the MWH related to that area is calculated.
This so called “Slicing and Dicing” method is the same as we deployed in Phase 1B except the
difference that Day-Ahead Energy Bid curve is used for DA energy and Real-Time Energy Bid
curve is used for RT energy.
$20 ME
$10 SupDec
$20 Non-
spin
$30 Non-
Spin
$30 NSpin
MW
00:50 00:55 Time
20
50
30
40
55
00:45
$55 LMP,
LMP MW = 55 MW
$40 LMP,
LMP MW = 50
MW
$50
$30
$20
PRICE
$30 Spin
$50 Spin
Day-ahead
45
$50 Spin
Exhibit C-27: “Slice and Dice” for ancillary service allocation – Economic Dispatch
The final output will be like the following table (The numbers are hypothetical)
Expected Energy
Type
Market Service
Type
Bid Price Energy
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Optimal Energy Spinning Reserve
Capacity
$50 0.415MWH
Optimal Energy Spinning Reserve
Capacity
$30 0.415MWH
Optimal Energy
Non Spinning
Reserve Capacity
$30 0.415MWH
Optimal Energy Non Spinning
Reserve Capacity
$20 0.83MWH
Optimal Energy Optimal Energy
Capacity
$20 0.83MWH
Day-ahead
Energy
Day-ahead Energy
Capacity
$20 1.66MWH
Residual and Exceptional Energy
When dealing with Residual Imbalance Energy, the bid segment needs to come from the
reference hour’s bid, not the current hour’s bid.
Exceptional Dispatch Energy is listed with its description of the Exceptional Dispatch Instruction
type. When there are multiple Exceptional Dispatch Instructions for the same interval, ONLY the
binding Exceptional Dispatch Instruction needs to be considered and outputted in the EE
calculation.
”NO BID” -- When Bid price is NULL
Because of the nature of Exceptional Dispatch Instructions, it is possible that an instruction will
NOT have a bid segment associated with it (the so-called out-of market) case. In such cases,
the Expected Energy type will be still filled in with the Exceptional Dispatch Energy type while
the Bid price will be filled as “NULL”. This would indicate to downstream systems that there is no
match for the big curve.
To further more illustrate the NO BID scenario, there are also other cases that there is no
Energy Bid at all for certain intervals. For example, there is the case that unit ramping from a
hour with bid into the next hour without bid, a ramping energy deviation could occur in the first
few intervals of the next hour. In such cases, use the NULL for bid price. The Expected Energy
type will stay as whatever applies for that energy portion. BASE Schedule Energy by nature
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does not have a Bid price.The Day-Ahead energy capacity and derate capacity sections
typically come with NULL price. However, some part of those capacity ranges can come with a
bid price because they overlaps with the bid curve.
Exhibit D-28 further illustrates how Expected Energy allocation is done in a more
comprehensive example.
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MW
00:00 00:05 Time
20
30
40
00:55
$50
$30
$20
PRICE
OOS – Overgeneration
$20 ME
$10 SupDec
$20 Non-
spin
$30 Non-
Spin
$30 NSpin
$30 Spin
$50 Spin
Day-ahead
$50 Spin
45
50
55 OOS – Reliability Must Run
I
J L L
H
N
A
E
F
K
B
C
D
M L
O G
$30 ME
$30 NSpin
$30 Spin
$50 Spin
$50 Spin
Day-ahead
Day-ahead
Day-ahead
HE 1 Bid Allocation HE 2 Bid Allocation
O L
Exhibit C-28 Exceptional Dispatch Energy and more complicated ramping scenarios
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The output of Exhibit D-28 for interval 00:55 to 00:00 (HE 1) will be something like the following
table (This time we use area label to indicate)
Expected Energy
Type
Market Service
Type
Bid Price Energy
EDE – Reliability
Must Run
Spinning Reserve $50 A
EDE – Reliability
Must Run
Spinning Reserve $30 B
EDE – Reliability
Must Run
Non Spinning
Reserve
$30 C
EDE – Reliability
Must Run
Non Spinning
Reserve
$20 D
EDE – Reliability
Must Run
Optimal Energy $20 E
Standard Ramping
Energy
Optimal Energy $20 F
Day-ahead Energy Day-ahead Energy $0 G
The output of Exhibit D-28 for interval 00:00 to 00:05 (HE 2) will be something like the following
table (This time we use area label to indicate)
Expected Energy
Type
Market Service
Type
Bid Price Energy
Residual Energy Spinning Reserve $50 H
Residual Energy Spinning Reserve $30 I
Optimal Energy Optimal Energy $30 J
Ramping Energy
Deviation
Day-ahead Energy $0 K
Standard
Ramping Energy
Day-ahead Energy $0 O (Negative)
Optimal Energy Day-ahead Energy $0 L (Negative)
EDE – Over-
generation
Day-ahead Energy $0 M (Negative)
Day-ahead Day-ahead Energy $0 N + O
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Energy
C.5 Market Data Correction
Prior to calculating Expected Energy, a review of the Trading Day’s Market results is performed.
After the Day-Ahead Market application (IFM) and the Real-Time Market application (RTM)
conclude for the Trading Day, the Market results are evaluated by CAISO Market Operations
Engineers and Market data corrections are performed, if appropriate.
For more details, refer to Section 8 of the BPM .
C.6 Publish Expected Energy Calculation
CAISO initially publishes Expected Energy at Trading Day plus one (T+1) Calendar Day. The
remaining Expected Energy publication schedule is consistent with the settlement schedule
provided in Section 2.3.2 of BPM for Settlements. CAISO will publish Expected Energy no later
than 2 business days in advance of the settlements schedule. This is to allow for Settlement
Statement processing time and validation. The data in Expected Energy shall match the
Settlement Statements when published.
Expected Energy is available on a secure basis to each Market Participant via the CMRI.
C.7 Multi-Stage Generating Resource Expected Energy
C.7.1 Real-Time Minimum Load Energy Calculation for Multi-Stage Generating Resources
The formulas for the Expected Energy calculation and allocation logic for Multi-Stage
Generating Resources do not differ from those for non Multi-Stage Generating Resources. The
only difference in the Expected Energy calculation for a Multi-Stage Generating Resource is the
calculation for the Real-Time Minimum Load Energy. This is to account for the possibility that
an MSG’s Minimum Load is different between the Day-Ahead Market and the Real-Time Market
as a result of the commitment of different MSG Configurations. The two instances where the
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calculation of Real-Time Minimum Load Energy is different for a Multi-Stage Generating
Resource are:
1- For any given Settlement Interval, if the Day-Ahead Market and Real-Time Market have
different committed MSG Configurations, and the Real-Time MSG Configuration
Minimum Load is greater than Day-Ahead Schedule, then the Real-Time Minimum Load
Energy will be the Energy below the Real-Time MSG Configuration Minimum Load and
above Day-Ahead Schedule. The Day-Ahead Minimum Load Energy will correspond to
the Day-Ahead MSG Configuration Minimum Load as shown below:
Note: for illustration purposes, only energy from Day-Ahead and Real-Time Dispatch schedules are shown. Assume Fifteen-Minute Market Schedules equal Real-Time Dispatch.
Exhibit C-29: Example of Real-Time Minimum Load Energy for Multi-Stage Generating Resource
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2- If the Day-Ahead Market and Real-Time Market have different committed MSG
Configurations, and the Real-Time MSG Configuration Minimum Load is less than the
Day-Ahead Schedule, there will be no Real-Time Minimum Load Energy. The Day-
Ahead Minimum Load Energy will correspond to the Day-Ahead MSG Configuration
Minimum Load as shown below:
Exhibit C-30: No Real-Time Minimum Load Energy: Multi-Stage Generating Resource
where Real-Time MSG Configuration is Below Day-Ahead MSG Configuration
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C.7.2 Real-Time Economic Dispatch Levels for Multi-Stage Generating Resources
The calculation of the upper and lower Real-Time Economic Dispatch levels for Multi-Stage
Generating Resources do not differ from those for non MSG resources. However, the following
rules apply in addition to the calculations detailed in section C.2.1.1.14 above.
For Multi-Stage Generating Resources, the Real-Time Economic Dispatch levels must always
fall within the operating range of the Real-Time active MSG Configuration. The formula used to
calculate these levels when there is no Real-Time Energy Bid for the active MSG Configuration
has been updated to comply with this convention. The formula is as follows:
RTLED = RTUED = Min { Pmax RT Config, Max [ DAS DA Config, Pmin RT Config ] }
The formula in section C.2.1.1.14 used when a Real-Time Energy Bid is present can be applied
to Multi-Stage Generating Resources without any changes. However, it is important to note that
the Real-Time Energy Bid Curve of the Real-Time active MSG Configuration will be used as the
input to that formula. Therefore, the calculated Real-Time Economic Dispatch levels will never
exceed the operating range of the Real-Time active MSG Configuration. In the case where a
Multi-Stage Generating Resource is dispatched uneconomically (for example due to Exceptional
Dispatch) the Real-Time active MSG Configuration may be a different MSG Configuration than
the economic dispatch. (See figures C-31 and C-32 below for illustration of examples.)
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Exhibit C-31: Real-Time Economic Dispatch Levels with Decremental Exceptional
Dispatch Instruction
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Exhibit C-32: Real-Time Economic Dispatch Levels with Incremental Exceptional
Dispatch Instruction
C.7.3 Residual Imbalance Energy for Multi-Stage Generating Resources
As detailed in section C.1, Residual Imbalance Energy is assigned the Real-Time Energy Bid
price from the reference hour. For Multi-Stage Generating Resources if the Real-Time active
MSG Configuration is the same during the intervals of the Residual Imbalance Energy and the
reference hour then the Real-Time Energy Bid price from that same MSG Configuration during
the Reference Hour will be assigned to the Residual Imbalance Energy as appropriate. This is
essentially the same process used for non- Multi-Stage Generating Resources.
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For Multi-Stage Generating Resources it is possible that the Residual Imbalance Energy may be
in a Real-Time active MSG Configuration that was not active in the reference hour (see Figure
C-33 below.) In such cases the Real-Time Energy Bid price from the last or next active MSG
Configuration will be assigned to the Residual Imbalance Energy depending on the direction of
the reference hour. If the reference hour is the prior hour (as in Figure C-33) then the Real-Time
Energy Bid price from the last active MSG Configuration in the reference hour will be assigned
to the Residual Imbalance Energy. If the reference hour is the hour after then the Residual
Imbalance Energy will use the Real-Time Energy Bid price from the first active MSG
Configuration in the next hour.
It is important to note that the range of the Real-Time Energy Bid Curve from the active MSG
Configuration in the reference hour may exclude some or all of the range of the Residual
Imbalance Energy. In the case of two over-lapping configurations some of the Residual
Imbalance Energy will be assigned the Real-Time Bid Price from the reference hour and
appropriate configuration. But some of the Residual Imbalance Energy will not be assigned any
Energy Bid price and will instead be settled using the Resource Specific Settlement Interval
LMP for each interval. For example, in figure C-33 below, the Residual Imbalance Energy is in
active configuration 2. The last active MSG Configuration from the reference hour is
configuration 3, the range of which overlaps with Configuration 2. The Real-Time Energy Bid
price from configuration 3 will be assigned to the portion of the Residual Imbalance Energy that
overlaps with the range of configuration 3. The remaining Residual Imbalance Energy will not be
assigned any Bid Price and will be settled using the Resource Specific Settlement Interval LMP
values for each interval.
If there was no overlap between configuration 3 and configuration 2 then all of the Residual
Imbalance Energy would be settled at the Resource Specific Settlement Interval LMP.
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Formatted: Font: 8 pt, Not Italic
Exhibit C-33: Residual Imbalance Energy After Real-Time Configuration Transition
CAISO Business Practice Manual BPM for Market Operations
Attachment D
COMMITMENT COST DETERMINATION
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D. Commitment Cost Determination
D.1. Introduction
In order to support the bid cost recovery process, the relevant commitment cost per
market and resource will need to be determined. This determination will first derive the
Self-Commitment Periods based on the bid set and relevant inter-temporal constraints.
This results into the separation of ISO commitment period versus self commitment
period. At the end, the relevant commitment cost will be calculated based on the
determined ISO commitment and self commitment period and relevant cost allocation
rules. In essence, the bid cost for the resource within the determined self-commitment
periods will not be included the bid cost recovery.
The commitment cost covers the following resources,
1. Startup cost and minimum load cost for generators including pump storage
resources in generation mode and tie generators;
2. Pumping cost and pump shutdown cost for participating loads and pump storage
resources in pumping mode.
In summary, this determination process will include the following three steps:
1. ELC/IFM/RUC self commitment type determination (sections D3, D4);
2. Real-time self commitment type determination (D6);
3. BCR commitment cost determination including individual cost dollar amount and
eligibility (D7).
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D.2. General Principles of Self Commitment Determination
CAISO will determine the commitment type for each time interval. The commitment type
shall be either “Self-Commitment” or CAISO-Commitment.”.
The Commitment Types shall be determined for ELC, IFM, RUC and RTUC for each
time interval. The time interval in the ELC, IFM and RUC is an hour, and the time interval
in RTUC is 15 minutes. The manual commitment by the CAISO in RTD (OOS) as
Exceptional Dispatch should be considered as CAISO commitment if the OOS
instruction is in its time horizon and also reported as OOS instructions.
The Commitment Types shall be determined for Generators, Tie Generators, Pump-
Storage Units in Generating Mode, Pump-Storage in Pumping Mode, and Participating
Load.
The key is how to determine Self-Commitment (including extended Self-Commitment);
once Self-Commitment is determined, CAISO Commitments can be determined readily
by excluding the Self-Commitments from the Commitment periods.
The following general principles apply to all CAISO Markets (IFM, RUC, HASP, STUC,
FMM, RTUC and RTM.
For a unit that is not a Fast Start unit, a time interval is considered a Self-
Commitment interval if the unit has in its Clean Bid an energy self-schedule, EIM
Base Schedule, load following up/down capacity or any AS self-provision (i.e.,
regulation up/down, spinning reserve, non-spinning reserve) in the interval or in
other intervals if it is determined by inference that the unit must be on in the
interval due to the unit’s physical constraints such as Minimum Up Time (MUT),
Minimum Down Time (MDT), Maximum Daily Startup (MDS).
For a unit that is a Fast Start unit (i.e. a unit that can provide non-spin when
offline), a time interval is considered a Self-Commitment interval if the unit has in
its Clean Bid an energy self-schedule, EIM Base Schedule, load following
up/down capacity or any AS self-provision except non-spinning reserve (i.e.,
regulation up/down and spinning reserve) in the interval or in other intervals if it is
determined by inference that the unit must be on in the interval due to the unit’s
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physical constraints such as Minimum Up Time (MUT), Minimum Down Time
(MDT), Maximum Daily Startup (MDS).
Self-commitment extension should be done to satisfy MUT first, MDT second,
and MDS last.
For purposes of this section, submittal of an EIM Base Schedule for EIM
resources shall be treated the same as a self-commitment in the IFM.
Note, operator manual commitment should be considered as CAISO Commitment even
though such manual commitment may be treated in a similar way as energy self-
schedules. If the CAISO decides to commit resource using the software automatically or
manually, the commitment should be considered as CAISO commitment.
In order to better describe our business rules and examples, following conventions are
used when describing commitment periods and their types.
Commitment Period – is a time period specified by a start-time/date and an end-
time/date within the time horizon of a market process in which the commitment statuses
are determined. The start-time is considered in the Commitment Period and the end-time
is considered not in the Commitment Period; mathematically, a Commitment Period is
denoted by [start-time, end-time).
Commitment Period Set – is a collection of Commitment Periods as its elements. In the
rest of the document, the Commitment Period Set is also referred to as Commitment
Periods although a Commitment Period Set can have zero, one or more elements in the
collection.
We use the following symbols in the following sections to simplify the description:
Definition of Commitment Periods and Set Operators
Symbol Meaning
[ … ) Time period, for example [1, 5) means starting at 1 (including 1) and
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ending at 5 (excluding 5).
{ …} Set
+ Union set operator, for example {[1, 2), [3,5)} + {[2 , 5)} = {[1, 5)}
* Intersection set operator, for example {[1, 3)} * {[2, 5)} = {[2, 3)}
- Minus set operator, for example {[1, 3)} – {[2, 5)} = {[1, 2)}
{ … }A-AppName Commitment Period Set determined by a specific market application;
the types are defined in Table D.2. For example {SCUC}A-IFM means
SCUC commitment type determined by IFM application.
{ … }S-AppName Commitment Period Set provided through the services for a specific
market application; the types are CAISO, SELF and UC. For example
{CAISO}S-IFM means the CAISO IFM Commitment Periods.
The following examples in this section illustrate in general how MUT, MDT and MDS are
used to extend the self-commitment periods. In these examples, hourly intervals are
used but the concepts illustrated by the examples also apply to RTM where the intervals
are 15-minutes. In the figures of these examples, S.C.P.E stands for Self-Commitment
Period Extension.
D 2.1 Minimum Up Time (MUT) Examples
Example 1 Basic MUT Self-Commitment period extension
A unit is ‘ON’ from 8:00 to 16:00. It has a self-schedule of 6 hours from 8:00 to 14:00. Its
MUT is 8 hours. Since the submitted self-schedule is less than the MUT of the resource,
the Self-Commitment Period is extended to 8:00 to 16:00 instead of 8:00 to 14:00. Note,
when a Self-Commitment Period can be extended in both directions, always extend it to
the hours after the self-schedule hours first because the ‘ON’ hours before the self-
schedule hours may not be due to the MUT but be due to an economic reason. This is
illustrated in Figure 1.
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Self-Commitment Period
Hour 0 238 14
MUT = 8 (hrs)
MDT =
MDS =
MUT
16
(hrs) 8
181 1MUTh E. S.C.P.
Figure 1 Basic MUT Self-Commitment period extension
Example 2 Forward and Backward MUT Self-Commitment period extension
A unit is ‘ON’ from 7:00 to 16:00. It has a self-schedule of 6 hours from 8:00 to 14:00. Its
MUT is 9 hours. Since the submitted self-schedule is less than the MUT of the resource,
the Self-Commitment Period is extended to 8:00 to 16:00 first then to 7:00 to 16:00 to
meet the MUT. This is illustrated in Figure 2.
Self-Commitment Period
Hour 0 238 14
MUT = 9 (hrs)
16
(hrs) 8E. S.C.P.
7
Figure 2 Forward and Backward MUT Self-Commitment period extension
D 2.2 Minimum Down Time (MDT) Examples
Example 3 Basic MDT Self-Commitment period extension
A unit is ‘ON’ from 8:00 to 18:00. The original self-commitment periods are from 8:00 to
11:00 and from 15:00 to 18:00. Its MDT is 6 hours. Since the hours between the two
original self-commitment periods are only 4 hours that is less than the MDT, the two
original self-commitment periods are merged into one from 8:00 to 18:00. This is
illustrated in Figure 3.
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Self-Commitment
Period
Hour 0 238 11
MDT=6 (hrs)
Self-Commitment
Period
15 18
E S.C.P.
n = 4 (hrs)
Figure 3 Basic MDT Self-Commitment period extension
D 2.3 Maximum Daily Start-Ups (MDS) Examples
Example 4 Basic MDS Self-Commitment period extension
A unit is ‘ON’ from 3:00 to 18:00. The original self-commitment periods are from 3:00 to
6:00, 10:00 to 13:00, and 15:00 to 18:00. Its MDS is 2. Since the number of the original
self-commitment periods is 3 (exceeding the MDS), then the original self-commitment
periods with the smallest time separation are merged to eliminate the violation. This is
illustrated in Figure 4.
Self-Commitment
Period
Hour 0 2310 13
Self-Commitment
Period
15 18
Self-Commitment
Period
3 6
Self-Commitment
Period
Hour 0 2310 13
Self-Commitment
Period
15 18
Self-Commitment
Period
3 6
Self-Commitment
Period Combination
Figure 4 Basic MDS Self-Commitment period extension – first example
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Example 5 MDS Self-Commitment period extension sequence
In the above example (MDS_1), if the second original self-commitment period is from
9:00 to 12:00 instead of 10:00 to 13:00, the time separation between the first and the
second original self-commitment period is the same as the time separation between the
second and the third original self-commitment period. In this case, the first two original
self-commitment periods based on the time sequence are merged to eliminate the
violation. This is illustrated in Figure 5
Self-Commitment
Period
Hour 0 239 12
Self-Commitment
Period
15 18
Self-Commitment
Period
3 6
Self-Commitment
Period
Hour 0 239 12
Self-Commitment
Period
15 18
Self-Commitment
Period
3 6
Self-Commitment
Period Combination
Figure 5 MDS Self-Commitment period extension sequence
Example 6 Not counting commitment period that is a continuation of previous day
If a unit initially is ‘ON’ and the first original Self-Commitment Period is from 0:00, the
unit’s MDS will be increased by 1 before it is used to determine if the MDS limitation is
violated. For example, a unit is initially ‘ON’ and it continues to be ‘ON’ from 0:00 to
18:00. It has three original self-commit periods. The first original self-commit period is
from 0:00 to 4:00. Its MDS is 2. After increasing the MDS by 1, the MDS limitation is not
violated any more. No merge is necessary. This is illustrated in Figure 6.
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Self-Commitment
Period Continuation
from Previous Day
Hour 0 238 11
Self-Commitment
Period
15 18
MDS = 2+1 = 3
4
Self-Commitment
Period
Figure 6 Not counting commitment period that is a continuation of previous day
Example 7 MDS Self-Commitment period extension in a more complex scenario
If in the previous example, the first original Self-Commitment Period is from 1:00 to 4:00
instead of 0:00 to 4:00, the rule used in the first example will be applied here first, i.e.,
the first original Self-Commitment Period will be extended to 0:00 to 4:00 to join the
commitment period of the previous day. Then the unit’s MDS will be increased by 1. This
is illustrated in Figure 7.
Self-Commitment
Period
Hour 0
238 11
Self-Commitment
Period
15 184
Self-Commitment
Period
1
Self-Commitment
Period Extension
Hour 0 238 11
Self-Commitment
Period
15 18
MDS = 2+1 = 3
4
Self-Commitment
Period
Figure 7 MDS Self-Commitment period extension in a more complex scenario
D.3. CAISO/Self-Commitment Extension in ELC – Examples
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D.3.1. Minimum Up-Time (MUT) Examples
Example 8 IFM Self-commitment Extension in ELC because of MUT
This example illustrates that an IFM Self-commitment period is extended to meet MUT in
ELC.
Assumptions:
SUT = 19 hours
MUT = 3 hours
MDT = 20 hours
Energy self-schedules submitted for the period of [4/4/07 22:00, 4/4/07 24:00); in
ELC the energy self-schedules submitted for 4/4/07 are also used as energy self-
schedules for [4/5/07 22:00, 4/5/07 24:00).
The IFM commits the unit for the period of [4/4/07 22:00, 4/4/07 24:00) and
determined that this period is IFM Self-commitment
There is no additional commitment in RUC
The ELC commits the unit for the periods of {[4/4/07 22:00, 4/5/07 01:00] ,
[4/5/07 22:00, 4/5/07 24:00)}
The entire ELC Commitment Periods will be ELC Self-commitment Periods because the
periods of {[4/4/07 22:00, 4/4/07 24:00), [4/5/07 22:00, 4/5/07 24:00]} are covered by
energy self-schedules, and the period [4/4/07 24:00, 4/5/07 01:00] is extended because
of MUT of 3 hours. This is illustrated in Figure 8.
04/04/07 04/05/07Trade Day - 1
ELCIFM
1513
ELCIFM
1513 22 24 22 24
MUT = 3 hrs
Figure 8 IFM Self-commitment Extension in ELC because of MUT
Example 9 IFM Self-Schedule Extension in ELC because of MUT and copied self-schedules
This example illustrates that an IFM Self-commitment period is extended to meet MUT in
ELC because of the self-schedules copied to the second day.
Assumptions:
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SUT = 19 hours
MUT = 3 hours
MDT = 20 hours
Energy self-schedule submitted for the period of [4/4/07 0:00, 4/4/07 2:00) and
this is accepted by SIBR because of existing energy schedules at the end of the
previous day, i.e., 4/3/07.
The IFM commits the unit for the period of [4/4/07 0:00, 4/4/07 2:00) and
determined that this period is IFM Self-commitment
There is no additional commitment in RUC
The ELC commits the unit for the periods of {[4/4/07 0:00, 4/4/07 2:00) ,
[4/4/07 22:00, 4/5/07 4:00)}
The ELC Self-commitment Periods should be [4/4/07 0:00, 4/4/07 2:00) and [4/5/07 0:00,
4/5/07 3:00). This is illustrated in Figure 9.
04/04/07 04/05/07Trade Day - 1
ELCIFM
1513 0 2 22 4
MUT = 3 hrs MUT = 3 hrs
Figure 9 IFM Self-Schedule Extension in ELC because of MUT and copied self-schedules
Example 10 Manual commitment treated as CAISO commitment
This example illustrates that a CAISO IFM commitment period due to operator manual
commitment prior to execution of the MPM is extended to meet MUT in ELC.
Assumptions:
SUT = 19 hours
MUT = 36 hours
MDT = 20 hours
Operator manually commit the unit in the period of [4/4/07 12:00, 4/4/07 24:00)
The IFM commits the unit for the period of [4/4/07 12:00, 4/4/07 24:00) and
determined that this period is CAISO IFM Commitment
There is no additional commitment in RUC
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The ELC commits the unit for the periods of {[4/4/07 12:00, 4/5/07 24:00]}
The entire ELC Commitment Period will be CAISO ELC Commitment Period because
the period of {[4/4/07 12:00, 4/4/07 24:00]} is extended to {[4/4/07 12:00, 4/5/07 24:00]}
because of MUT of 36 hours. This is illustrated in Figure 10.
04/04/07 04/05/07Trade Day - 1
ELCIFM
1513 12 24 24
MUT = 36 hrs
CAISO ELC Commitment
Figure 10 Manual commitment treated as CAISO commitment
D.3.2. Minimum Down Time (MDT) Examples
Example 11 - IFM Self-commitment extension in ELC because of MDT
This example illustrates that an IFM Self-commitment period is extended to meet MDT in
ELC.
Assumptions:
SUT = 19 hours
MUT = 10 hours
MDT = 20 hours
Energy Self Schedule submitted for the period of [4/4/07 08:00, 4/4/07 18:00)
The IFM commits the unit for the period of [4/4/07 08:00, 4/4/07 18:00) and
determined that this period is IFM Self-commitment, i.e.,
{SELF}S-IFM = {UC}S-IFM = [4/4/07 08:00, 4/4/07 18:00)
There is no additional RUC commitment
The ELC commits the unit for the following periods:
{SELF}S-ELC = {UC}S-ELC = {[4/4/07 08:00, 4/5/07 18:00]}
The entire ELC Commitment Period will be ELC Self-Commitment Period because the
energy self schedule submitted for the period of [4/4/07 08:00, 4/4/07 18:00) is also used
as energy self schedule for the period of [4/5/07 08:00, 4/5/07 18:00), and the period of
{[4/4/07 18:00, 4/5/07 08:00)} is less than the MDT of 20 hours. This is illustrated in
Figure 11.
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SUT = 19 (hrs)
MDT = 20 (hrs)
Trade Day Trade Day + 1Trade Day - 1
ELCIFM
151310
IFM Commitment
8 818 18
ELC Commitment
SExt
Figure 11 IFM Self-commitment extension in ELC because of MDT
Example 12 Self-Commitment Extension in ELC due to combination of MUT and MDT
This example illustrates Self-Commitment Extension in ELC due to combination of MUT
and MDT.
Assumptions:
SUT = 19 hours
MUT = 5 hours
MDT = 20 hours
Energy self-schedule submitted for the periods of [4/4/07 0:00, 4/4/07 2:00) and
[4/4/07 22:00, 4/4/07 24:00), which is accepted by SIBR because of existence of
commitment period at the end of 4/3/07.
The IFM commits the unit for the period of [4/4/07 0:00, 4/4/07 2:00) and
[4/4/07 22:00, 4/4/07 24:00) and determined that these periods are IFM Self-
commitment
There is no additional commitment in RUC
The ELC commits the unit for the periods of {[4/4/07 0:00, 4/4/07 2:00) ,
[4/4/07 22:00, 4/5/07 24:00)}. Note, the energy self-schedules submitted for IFM
of 4/4/07 are also used for ELC of 4/5/07.
All ELC Commitment Periods will be ELC Self-commitment Periods because the periods
of {[4/4/07 0:00, 4/4/07 2:00), [4/4/07 22:00, 4/5/07 2:00), and [4/5/07 22:00, 4/5/07
24:00) are covered by energy self-schedules; and the period [4/4/07 22:00, 4/5/07 2:00)
is extended to [4/4/07 22:00, 4/5/07 3:00) because of MUT of 5 hours; and then the
periods of [4/4/07 22:00, 4/5/07 3:00) and [4/5/07 22:00, 4/5/07 24:00) are merged due
to the MDT of 20 hours. This is illustrated in Figure 12.
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04/04/07 04/05/07Trade Day - 1
ELCIFM
1513 0 2 0 222
MUT = 5 hrsMUT = 5 hrs
22 24
MDT = 20 hrs
Figure 12 Self-Commitment Extension in ELC due to combination of MUT and MDT.
Example 13 – CAISO IFM Commitment extends Self-commitment extension in ELC
This example illustrates the situation where the CAISO IFM/RUC commitments following
a self-schedule commitment period extends the ELC Self-commitment periods due to
MDT in ELC.
Assumptions:
SUT = 19 hours
MUT = 10 hours
MDT = 20 hours
Energy Self Schedule submitted for the period of [4/4/07 08:00, 4/4/07 18:00)
The IFM commits the unit for the period of [4/4/07 08:00, 4/4/07 18:00) and
determined that this period is IFM Self-commitment, i.e.,
{SELF}S-IFM = {UC}S-IFM = [4/4/07 08:00, 4/4/07 18:00)
The RUC commits the unit for the period of [4/4/07 08:00, 4/4/07 24:00) and
determined the following RUC Commitment periods:
{UC}S-RUC = [4/4/07 08:00, 4/4/07 24:00)
{SELF}S-RUC = {SELF}S-IFM = [4/4/07 08:00, 4/4/07 18:00)
{CAISO}S-RUC = [4/4/07 18:00, 4/4/07 24:00)
Then we have:
The ELC commits the unit for the following periods:
{UC}S-ELC = {[4/4/07 08:00, 4/5/07 18:00)}
{SELF}S-ELC = {[4/4/07 08:00, 4/4/07 18:00), [4/5/07 00:00, 4/5/07 18:00)}
{CAISO}S-ELC = {[4/4/07 18:00, 4/4/07 24:00)}
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The entire ELC Commitment Period would have been ELC Self-commitment Period if
there were no additional RUC commitment during the period of [4/4/07 18:00, 4/4/07
24:00) due to MDT of 20 hours. However, the 24-hour time horizon RUC does not see
far enough to know that the period of [4/4/07 18:00, 4/4/07 24:00) should be considered
RUC Self-commitment period due to MDT. If a 48-hour time horizon RUC is used, the
period of [4/4/07 18:00, 4/4/07 24:00) should be considered RUC Self-commitment
period and consequently ELC Self-commitment period. However, the outcome of the first
day for ELC is not important because ELC commitments are only used for the second
day. This is illustrated in Figure 13.
04/05/07
ELC SELF
04/04/07Trade Day - 1
ELCIFM
1513
24 248 18
Self IFM CAISO RUC
CAISO ELC
Figure 13 CAISO IFM Commitment extends Self-commitment extension in ELC
Example 14 IFM/RUC automatic commitment treated as CAISO commitment in subsequent ELC
This example illustrates that a CAISO IFM commitment period due to SCUC optimization
is extended to meet MUT in the subsequent ELC.
Assumptions:
SUT = 19 hours
MUT = 36 hours
MDT = 20 hours
Energy bids are submitted for every hours of 4/4/07 on 4/3/07; no self-schedules
or self-provisions are submitted
The IFM executed on 4/3/07 commits the unit in the period of [4/4/07 08:00,
4/4/07 24:00) and determined that the entire period is CAISO IFM commitment
Then,
The ELC executed on 4/3/07 commits the unit for the period of [4/4/07 08:00,
4/5/07 20:00) to satisfy MUT of 36 hours and determined that this period is
CAISO ELC Commitment. This is illustrated in Figure 14.
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04/04/07 04/05/0704/03/07
ELCIFM
1513CAISO IFM Commitment
0
CAISO ELC Commitment
24 24
MUT = 36 hrs
Figure 14 IFM/RUC automatic commitment treated as CAISO commitment in subsequent ELC
D.4. CAISO/Self-Commitment Extension in IFM - Examples
D.4.1. Minimum Up-Time (MUT) Examples
SIBR ensures that MUT are satisfied for the energy self-schedules except for the self-
schedules at the end of the day. The following examples illustrate this situation.
Example 15 IFM Self-Commitment Period at the End of the Day
A unit is ‘ON’ from 19:00 to 24:00. It has DAM self-schedules for 3 hours from 21:00 to
24:00. Its MUT is 5 hours. The submitted self-schedule is less than the MUT of the
resource and this is accepted by SIBR because the set of consecutive self-schedules
are at the end of the day. Self-commitment Period is [21, 24). Self-Commitment Period is
not extended to [19:00, 24:00) because the IFM commits the unit in [19:00, 21:00) for
economic reasons and not for MUT. Therefore, [19, 21) is considered as CAISO
commitment and not an extension of self-commitment. This is illustrated in Figure 15.
Self-
Commitment
Period
Hour 0
24
10
19
MUT = 5 (hrs)
21
Figure 15 IFM Self-Commitment Period at the end of the day
Example 16 CAISO Commitment continuation of Self-Commitment Period from Previous Day
Continue from the previous example; the unit had energy self-schedules in [21, 24) of
the previous day. The unit is ‘ON’ from 0:00 to 4:00 in the current trading day. It does not
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have any self-schedule from 0:00 to 4:00 in the current trading day. Its MUT is 5 hours.
Since the MUT has already been satisfied in the previous day, the commitments in [0. 4)
of the current day is CAISO-Commitment. This is illustrated in Figure 16.
021
MUT = 5 ( hrs)
(hrs) 4
2 4
CAISO
Figure 16 CAISO Commitment continuation of Self-Commitment Period from Previous Day
Example 17 IFM Self-Commitment Period at the End of the Day not satisfying MUT
A unit is ‘ON’ from 21:00 to 24:00. It has DAM self-schedules for 3 hours from 21:00 to
24:00. Its MUT is 5 hours. The submitted self-schedule is less than the MUT of the
resource and this is accepted by SIBR because the set of consecutive self-schedules
are at the end of the day. Self-commitment Period is [21, 24). This is illustrated in Figure
17.
Self-
Commitment
Period
Hour 0
24
10
MUT = 5 ( hrs)
21
Figure 17 IFM Self-Commitment Period at the end of the day not satisfying MUT
Example 18 Self-Commitment continuation of Self-Commitment Period from Previous Day
Continue from the previous example; the unit had energy self-schedules in [21:00,
24:00) of the previous day. The unit is ‘ON’ from 0:00 to 4:00 in the current trading day. It
does not have any self-schedule from 0:00 to 4:00 in the current trading day. Since its
MUT of 5 hours has not been satisfied, the Self-Commitment Period of the previous day
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will be extended into the current day to meet the MUT; resulting in [0:00, 2:00) as Self-
Commitment Period. But there is no need to report the portion of the Self-Commitment
Period in the previous trade day, i.e., [21:00, 24:00) of the previous trading day. The
commitment period of [3:00, 4:00) is CAISO Commitment. This is illustrated in Figure 18.
021
MUT = 5 (hrs)
(hrs) 5E. S.C.P.
2 4
Figure 18 Self-Commitment continuation of Self-Commitment Period from Previous Day
Example 19 IFM/RUC automatic commitment treated as CAISO commitment in next IFM
This example illustrates that a CAISO IFM commitment period due to SCUC optimization
is extended to meet MUT in the next IFM.
Assumptions:
SUT = 10 hours
MUT = 36 hours
MDT = 12 hours
Low energy bids are submitted for every hours of 4/4/07 on 4/3/07; no self-
schedules or self-provisions are submitted
High energy bids are submitted for every hours of 4/5/07 on 4/4/07; no self-
schedules or self-provisions are submitted
The IFM executed on 4/3/07 commits the unit in the period of [4/4/07 00:00,
4/4/07 24:00) and determined that the entire period is CAISO IFM commitment.
There are no additional ELC commitments for 4/5/07.
Then,
The IFM executed on 4/4/07 commits the unit for the period of [4/5/07 00:00,
4/5/07 12:00) to satisfy MUT of 36 hours and determined that this period is
CAISO IFM Commitment. This is illustrated in Figure 19.
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04/04/07 04/05/0704/03/07
ELCIFM
1513CAISO IFM Commitment
0
CAISO IFM Commitment
24 24
MUT = 36 hrs
Figure 19 IFM/RUC automatic commitment treated as CAISO commitment in next IFM
D.5. Pump Storage Resources and Participating Loads
A pump-storage unit has three operating modes: generating mode, pumping mode and
offline mode. The multi-state model for a pump storage unit is shown below. According
to the current implementation, a transition from the pumping mode to the generating
mode must go through the offline mode; and a transition from the generating mode to
the pumping mode must also go through the offline mode. The Minimum Down-Time
(MDT), specified in minutes, is the minimum time the pump-storage unit must stay offline
before transitioning into either the pumping mode or the generating mode. The same
MDT is used for both the pumping mode and the generation mode.
startup
GC
En
pumpp
GEn
min
GEn max
GEn3
GEn2
GEn1
GEn
3;En
Gp
2;En
Gp
1;En
Gp
En;min
Gp
En;max
Gp
fix
LEn
Multi-State Model for Pumped Storage Unit
A pump-storage unit has separate Minimum Up Time (MUT) for pumping and generating
mode. A pump-storage unit has separate Maximum Daily Startup number for pumping
and generating mode.
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The commitment types of a pump storage unit operating in generating mode are
determined in the same way that the commitment types of other generators are
determined as illustrated in Section D.3.
A pump storage unit is considered self-committed in pumping mode in an hour in a
market if there is an energy self-schedule in the pumping mode in the market. The self-
commitment period extensions for a pump storage unit in pumping mode follow the
same rules and examples as specified so far except that separate MUT and MDS are
used for operating in pumping mode.
A Participating Load is a Load with a Participating Load Agreement (PLA) and is certified
for demand response and may be able to provide Non-Spinning Reserve.
In MRTU software Release 1, a Participating Load (PL) will be modeled by a pair of
fictitious Non-Participating Load and fictitious Generator. The PL inter-temporal
constraints are converted outside of Siemens application for the fictitious Generator as
follows:
Load Curtailment Time => Generator Startup Time,
Minimum Load Reduction Time => Generator Minimum Up Time,
Minimum Base Load Time => Generator Minimum Down Time (set to zero), and
Maximum Number of Daily Load Curtailments => maximum number of daily
generator startups.
Note all these load inter-temporal parameters are constant values not dependent on time
load being curtailed.
The commitment types of the fictitious generators are determined in the same way as
other generators as illustrated so far.
D.6. Real-time Self Commitment Type determination
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D.6.1. Introduction
While the self commitment types of ELC, IFM and RUC commitment are determined by
the market applications, the real-time self commitment types are determined on an after-
the-fact base since this determination requires a full history of the DA and real-time
commitment status. The following table lists the market processes and their expected
behavior:
Table D.1 Market Processes and their expected behavior
Day Time Activity
D-2 13:00-15:00 ELC executes and passes the commitment types of
extremely long start resources to the next IFM
D-1 10:00-13:00 IFM executes and determines the IFM commitment
types (including the ELC commitment results)
D-1 10:00-13:00 RUC executes and determines the RUC commitment
types (including the ELC and IFM commitment results)
D-1 13:00 Final IFM and RUC commitment types available to
RTUCs; i.e., {UC}S-IFM, {SELF}S-IFM, {UC} S-RUC
D-1 20:07:30 The STUC executed at this time has the first hour of
day D in the time horizon; STUC with operator approval
can make binding unit commitment decisions for the 15-
minute intervals in the period of [00:00, 01:00) in Day D.
STUC will make the binding commitment type {UC}S-
STUC available to subsequent RTUC, RTD and MQS. If
there is any energy self-schedule or AS self-provision in
hour [21:00, 22:00) of day D-1, the commitment by
STUC for hour [00:00, 01:00) of day D is based on
copied self-schedule. However, the commitment type
will be determined later by MQS using the bid actually
submitted for [00:00, 01:00) of day D.
D-1 22:52:30 The HASP executed at this time has the first hour of
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day D in the time horizon using the bid submitted for
this hour. HASP with operator approval can make
binding unit commitment decisions for the 15-minute
intervals in the period of [00:00, 01:00) in Day D. HASP
will make the binding commitment type {UC}S-HASP
available to subsequent RTUC, RTD and MQS.
D-1 to D any time OOS instructions can override the commitment status
made by the SCUC processes. All OOS instructions
(Startup, Shut Down, Min, Max and Fix) can alter the
commitment status determined by SCUC including
those pre-specified by the operator prior to SCUC
execution. Such OOS instructions should be reflected in
the RTUC commitment type {UC}S-RTUC. In other words,
the time intervals in which the unit is off by OOS should
not be included in the {UC} S-RTUC and the time intervals
in which the unit is On by OOS should be included in
the {UC} S-RTUC. The OOS instructions are provided to
MQS to allow MQS to determine the commitment types
for intervals in {UC} S-RTUC. If an OOS instruction occurs
in the middle of a 15 minute interval, it will affect the
commitment status and type for the entire 15-minutes
interval in the {UC}S-RTUC.
D 23:22:30 The RTUC3 executed at this time is the last process
that has the last 15-minute interval in day D in the time
horizon. RTUC3 makes binding unit commitment
decisions for the last 15-minute interval in Day D.
RTUC3 shall make the binding commitment decision
{UC}S-RTUC3 available to subsequent RTUC, RTD and
MQS.
D 23:37:30 The RTUC4 executed at this time is the first process
that has the first 15-minute interval in day D+1 as
binding commitment interval. RTUC4 shall make the
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binding commitment decision {UC}S-RTUC4 for day D+1
available to subsequent RTUC, RTD and MQS.
D After 24:00 All commitment decisions for day D are final and
available for MQS to determine the RTM commitment
types.
Table D.2 Input Data Needed to determine Commitment Types
Data Source Description
{UC}S-IFM IFM For each resource in each IFM time horizon,
the IFM Commitment Periods denoted by the
set {UC}S-IFM consists of all the hours in which
the resource is “On” as determined by the IFM
SCUC including the previous binding ELC
Commitment decisions passed to the current
DAM, and those operator pre-specified
commitment decision made at the beginning of
the MPM process prior to the current IFM
execution.
{SELF}S-IFM IFM The IFM Self-commitment Periods denoted by
the set {SELF}S-IFM consists of all the previous
ELC Self-commitment Periods and the self-
commitment periods determined by the current
DAM energy Self-Schedules and AS Self-
Provisions. Note, the operator pre-specified
commitment decisions made at the beginning
of the DAM process prior to MPM/RRD
execution shall not be considered as “Self-
Commitment” even though such manual
commitments may be treated by the SCUC
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in a similar way as energy self-schedules.
If the CAISO decides to commit a resource
using the software automatically or
manually, the commitment should be
considered as CAISO commitment.
{UC} S-RUC RUC For each resource in each RUC time horizon,
the RUC Commitment Periods denoted by the
set {UC}S-RUC consists of all the hours in which
the resource is “On” as determined by the
RUC SCUC including the IFM Commitment
decisions passed to the RUC.
{UC} S-RTUC RTUC The RTUC application includes HASP, STUC,
RTUC3 and RTUC4. {UC} S-RTUC includes all
intervals of “On” status that are binding as
determined by previous processes (IFM, RUC,
ELC, RTUC, OOS) and the current process.
DA Energy Self-
Schedules
SIBR The energy self-schedules must be the
originally submitted energy self-schedules.
DA AS Self-provisions
(including LFD and
LFU)
IFM The AS self-provisions must be the originally
submitted AS self-provisions.
RT Energy Self-
Schedules
SIBR The energy self-schedules must be the
originally submitted energy self-schedules.
RT Base Schedules SIBR The base schedules must be the originally
submitted base schedules.
RT AS Self-provisions
(including LFD and
LFU)
SIBR The AS self-provisions must be the originally
submitted AS self-provisions.
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RT RMR Requirement RT MPM This is the result of RT MPM process.
MUT Master File Minimum Up Time (for pump storage resource,
separate values in pumping and generating
modes)
MDT Master File Minimum Down Time
MDS Master file Maximum Number of Daily Startup (for pump
storage resource, separate values in pumping
and generating modes)
Fast Start Master File Fast Start indicates that the unit can deliver
energy within 10 minutes from off-line status.
On Time RTM
application
On Time is the period between the beginning
of the interval when the unit was turned “On”
and the end of the last contiguous “On” interval
before the unit is turned “Off”. In other words,
On Time is measured at a given time by the
minutes elapsed since the resource was most
recently started up at the Minimum Load and
continuously stayed online.
D.6.2. RTM Self-Commitment Type Determination for Generator Resources
The definitions and rules in this subsection apply to generator resources, inter-tie
generator resources, and pump-storage generator resources operating in generating
mode.
Def 1 A Real-Time Market (RTM) Commitment Period is a set of consecutive intervals of “On” status generated by the RTUCs and STUC, including the commitment decisions made by ELC, IFM and RUC and not altered by the RTUCs, for a resource in a given time period.
Def 2 The length of a RTM Commitment Period is measured by the difference between the start-time and the end-time.
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Def 3 A Super RTM Commitment Period is the longest RTM Commitment Period among the RTM Commitment Periods that have nonempty intersection for the resource in the given period.3
Def 4 A Sub RTM Commitment Period is a RTM Commitment Period that is shorter than at least one RTM Commitment Period that has nonempty intersection with it for the resource in the given period.
Def 5 A Super RUC Commitment Period is the longest RUC Commitment Period among the RUC Commitment Periods that have nonempty intersection for the resource in a given period.
Def 6 A Super IFM Commitment Period is the longest IFM Commitment Period among the IFM Commitment Periods that have nonempty intersection for the resource in a given period.
Def 7 A RTM Self-Commitment Period is a RTM Commitment Period that is resulted from energy self-schedules, AS self-provisions and their interaction with inter-temporal constraints imposed by MUT, MDT and MDS for the resource in the given period.
Def 8 A Basic RTM Self-Commitment Period is a RTM Self-Commitment Period that is resulted directly from energy self-schedules, and AS self-provisions without considering their interaction with inter-temporal constraints imposed by MUT, MDT and MDS for the resource in the given period.
Def 9 A MUT Extended RTM Self-Commitment Period is a RTM Self-Commitment Period that is resulted from one or more Basic RTM Self-Commitment Periods and their interaction with inter-temporal constraints imposed by MUT for the resource in the given period. The MUT used here is rounded up to the next 15-minute commitment interval if it is not already in multiples of 15-minutes. A Basic RTM Self-Commitment Period is referred to as a MUT Extended RTM Self-Commitment Period after the MUT Extension process even if no MUT extension is made.
Def 10 A MDT Extended RTM Self-Commitment Period is a RTM Self-Commitment Period that is resulted from one or more MUT Extended RTM Self-Commitment Period and their interaction with inter-temporal constraints imposed by MDT for the resource in the given period. The MDT used here is rounded up to the next 15-minute commitment interval if it is not already in multiples of 15-minutes. A MUT Extended RTM Self-Commitment Period is referred to as a MDT Extended RTM Self-Commitment Period after the MDT Extension process even if no MDT extension is made.
Def 11 A MDS Extended RTM Self-Commitment Period is a RTM Self-Commitment Period that is resulted from one or more MDT Extended RTM Self-Commitment Period and their interaction with inter-temporal constraints imposed by MDS for the resource in the given period. A MDT Extended RTM Self-Commitment Period is referred to as a MDS Extended RTM Self-Commitment Period after the MDS Extension process even if no MDS extension is made.
3 The given period is not limited within the Trading Day; the given period will be specified in the context of the rules. A Super RTM Commitment Period loosely speaking is a longest continuous RTM Commitment Period which contains many Sub RTM Commitment Periods.
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Def 12 A BCR RTM Self-Commitment Period is a RTM Self-Commitment Period that is resulted from a MDS Extended RTM Self-Commitment Period by excluding its intersections with IFM Commitment Periods and RUC Commitment Periods for the resource in a given period. A MDS Extended RTM Self-Commitment Period is referred to as a BCR Extended RTM Self-Commitment Period after the BCR Exclusion process even if no truncation is made to exclude the intersection with any IFM Commitment Period or RUC Commitment Period.
Def 13 The BCR RTM Self-Commitment Periods, denoted by {SELF}RTM, shall be the union of all BCR RTM Self-Commitment Commitment Periods, for a resource in a given time period.
Def 14 The BCR RTM Commitment Periods, denoted by {UC}RTM, shall be the union of all RTM Commitment Periods excluding their intersections with IFM Commitment Periods and RUC Commitment Periods for the resource in the given period.
Def 15 The BCR CAISO RTM Commitment Periods, denoted by {CAISO}RTM, shall be the union of all BCR RTM Commitment Periods excluding their intersections with the BCR RTM Self-Commitment Periods, for a resource in a given time period.
Def 16 The RMR RTM Commitment Periods, denoted by {RMR}RTM, shall be the union of all the time intervals where an RMR resource has any positive (i.e., non-zero) DAM RMR Requirements or positive RTM RMR Requirements.
Def 17 The RTM MUT Backtrack Window, is a period that has a configurable length and ends at the beginning of the current Trading Day. The configurable length is 10080 minutes (i.e., 7 days) by default.
Def 18 The RTM MDT Backtrack Window, is a period that has a configurable length and ends at the end of the current Trading Day. By default the configurable length is 4320 minutes (i.e., 3 days).
Def 19 The RTM MDT Forthcoming Window, is a period that has a configurable length and starts at the end of the current Trading Day. By default the configurable length is 1440 minutes (i.e., 1 day).
A RTM Self-Commitment Period will go through the following stages in arriving at the
final usable form for Bid Cost Recovery (BCR).
Basic MUT Extension MDT Extension MDS Extension BCR Exclusion
The Basic RTM Self-Commitment Periods for a resource in a given period are
constructed as follows:
Rule 1. If the resource is not a fast start unit, identify all the hours in which the
resource has any of the following in the trading day: RTM energy self-
schedule, RTM LFU, RTM LFD, RTM Regulation Up self-provision, RTM
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Regulation Down self-provision, Spinning Reserve self-provision or Non-
Spinning Reserve self-provision in the given period.
Rule 2. If the resource is a fast start unit, identify all the hours in which the
resource has any of the following in the trading day: RTM energy self-
schedule, RTM LFU, RTM LFD, RTM Regulation Up self-provision, RTM
Regulation Down self-provision, or Spinning Reserve self-provision in the
given period.
Rule 3. Each set of consecutive hours identified in Rule 1 or Rule 2, is a Basic
RTM Self-Commitment Period.
The MUT Extended RTM Self-Commitment Periods for a resource in the current Trading
Day are constructed in sequence as follows:
Rule 4. If a Basic RTM Self-Commitment Period [h, e) is a Sub RTM Commitment
Period4, and if the length of the Basic RTM Self-Commitment Period is
less than the current MUT of the resource minus the “On Time” evaluated
at the beginning of the Basic RTM Self-Commitment Period, i.e., if (e-
h)<MUTOn_Time, the Basic RTM Self-Commitment Period must be
extended to the minimum of h+MUTOn_Time, the end of the Super RTM
Commitment Period that has intersection with the Basic RTM Self-
Commitment Period that is being extended, or the end of the current
Trading Day.5
(Note, this step shall address several special cases:
i. If a Basic RTM Self-Commitment Period [h, e) in a Trading Day is
a Sub RTM Commitment Period that starts at the beginning of the
day, and the resource was “On” at the end of the previous Trading
Day, and if the length of the Basic RTM Self-Commitment Period
is less than the MUT of the resource minus the “On Time”
4 Only a Sub RTM Commitment Period can be extended within the Super RTM Commitment Period that contains it. A Super RTM Commitment Period within a given period cannot be extended within the given period because a Super RTM Commitment Period represents the entire number of intervals having “On” status in the given period.
5 The “On-Time” evaluated at the beginning of the Basic RTM Self-Commitment Period represents how long the unit has been in “On” status continuously until the beginning of the Basic RTM Self-Commitment Period. The Basic RTM Self-Commitment Period only needs to be extended to cover the remaining of the MUT counted from the beginning of the Basic RTM Self-Commitment Period.
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evaluated at the end of the previous Trading Day, i.e., if (e-
h)<MUTOn_Time, the Basic RTM Self-Commitment Period must
be extended to the minimum of h+MUTOn_Time, the end of the
Super RTM Commitment Period that has intersection with the
Basic RTM Self-Commitment Period that is being extended, or the
end of the current Trading Day.6
ii. If a Basic RTM Self-Commitment Period [h, e) in a Trading Day is
a Sub RTM Commitment Period that starts at the beginning of the
day, and the resource was “Off” at the end of the previous Trading
Day, and if the length of the Basic RTM Self-Commitment Period
is less than the MUT of the resource, i.e., if (e-h)<MUT, the Basic
RTM Self-Commitment Period must be extended to the minimum
of h+MUT, the end of the Super RTM Commitment Period that has
intersection with the Basic RTM Self-Commitment Period that is
being extended, or the end of the current Trading Day.
iii. If a Basic RTM Self-Commitment Period [h, e) in a Trading Day is
a Sub RTM Commitment Period that does not start at the
beginning of the day, and if the length of the Basic RTM Self-
Commitment Period is less than the MUT of the resource minus
the “On Time” evaluated at the beginning of the Basic RTM Self-
Commitment Period, i.e., if (e-h)<MUTOn_Time, the Basic RTM
Self-Commitment Period must be extended to the minimum of
h+MUTOn_Time, the end of the Super RTM Commitment Period
that has intersection with the Basic RTM Self-Commitment Period
that is being extended, or the end of the current Trading Day.
iv. If a Basic RTM Self-Commitment Period [h, e) in a Trading Day is
not a Sub RTM Commitment Period, (in other words, if it is a
Super RTM Commitment Period), even if the length of the Basic
RTM Self-Commitment Period is less than the MUT of the
resource minus the “On Time” evaluated at the beginning of the
6 The “On_Time” of the previous days are counted towards meeting the MUT of the Basic RTM Self-Commitment.
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Basic RTM Self-Commitment Period, i.e., if (e-h)<MUTOn_Time,
the Basic RTM Self-Commitment Period will not be extended
because the resource will be off beyond the end of the Basic RTM
Self-Commitment Period.)
Rule 5. If in the RTM MUT Backtrack Window there is a Super RTM Commitment
Period [s, o) that intersects with a MDS Extended RTM Self-Commitment
Period [m, o) that ends at the end of the previous Trading Day, if the
length of the Super RTM Commitment Period in the RTM MUT Backtrack
Window is X minutes less than the current MUT of the resource minus the
On_Time evaluated at the beginning of the Super RTM Commitment
Period in the RTM MUT Backtrack Window, and if there is a Super RTM
Commitment Period [o, e) that is in the current Trading Day and starts at
the beginning of the current Trading Day, a MUT Extended Commitment
Period [o, min(X, e)) shall be defined with the start-time being the
beginning of the current Trading Day and the end-time being the smaller
of X minutes after the beginning of the current Trading Day and the end of
the Super RTM Commitment Period that is in the current Trading Day and
starts at the beginning of the current Trading Day.
Rule 6. After this MUT extension process, the Basic RTM Self-Commitment
Periods are referred to as MUT Extended RTM Self-Commitment Periods
regardless of whether any extension was made.
Rule 7. If the MUT Extended RTM Self-Commitment Periods generated by the
MUT extension process as described by Rule 4 through Rule 6 have
nonempty intersections, the MUT Extended RTM Self-Commitment
Periods having nonempty intersections should be merged.
The MDT Extended RTM Self-Commitment Periods for a resource in a Trading Day are
constructed in sequence as follows:
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Rule 8. If two disjoint and nonadjacent MUT Extended RTM Self-Commitment
Periods intersect with the same Super RTM Commitment Period7 in the
current Trading Day, and if the two MUT Extended RTM Self-
Commitment Periods are apart from each other by less than the current
MDT of the resource, the two MUT Extended RTM Self-Commitment
Periods should be merged to form a MDT Extended RTM Self-
Commitment Period.
Rule 9. If a MUT Extended RTM Self-Commitment Period or a MDT Extended
RTM Self-Commitment Period resulted from Rule 8 in the current Trading
Day intersects the same Super RTM Commitment Period with a disjoint,
nonadjacent and earlier Super RUC Commitment Period in the RTM MDT
Backtrack Window, and if the MUT/MDT Extended RTM Self-
Commitment Period is apart from the Super RUC Commitment Period by
less than the current MDT of the resource, the start-time of the MUT/MDT
Extended RTM Self-Commitment Period resulted from Rule 8 should be
extended to the later of the end-time of the Super RUC Commitment
Period or the beginning of the current Trading Day.
Rule 10. If a MUT Extended RTM Self-Commitment Period or a MDT Extended
RTM Self-Commitment Period resulted from Rule 8 and Rule 9 in the
current Trading Day intersects the same Super RTM Commitment Period
with a disjoint, nonadjacent and earlier MDS Extended RTM Self-
Commitment Period in the RTM MDT Backtrack Window, and if the
MUT/MDT Extended RTM Self-Commitment Period is apart from the
MDS Extended RTM Self-Commitment Period by less than the current
MDT of the resource, the start-time of the MUT/MDT Extended RTM Self-
Commitment Period should be extended to the later of the end-time of the
MDS Extended RTM Self-Commitment Period or the beginning of the
current Trading Day.
7 Since the Super RTM Commitment Period contains both MUT Extended RTM Self-Commitment Periods, the unit is “On” during the gap between the two MUT Extended RTM Self-Commitment Periods. If two MUT Extended RTM Self-Commitment Periods do not intersect with a common Super RTM Commitment Period, the unit must have “Off” status during the gap between the two MUT Extended RTM Self-Commitment Periods.
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Rule 11. If a MUT Extended RTM Self-Commitment Period or a MDT Extended
RTM Self-Commitment Period resulted from Rule 8 through Rule 10 in
the current Trading Day, intersects the same Super RTM Self-
Commitment Period with a disjoint, nonadjacent and later Super RUC
Commitment Period in the current Trading Day, and if the MUT/MDT
Extended RTM Self-Commitment Period is apart from the Super RUC
Commitment Period by less than the current MDT of the resource, the
end-time of the MUT/MDT Extended RTM Self-Commitment Period
should be extended to the start-time of the Super RUC Commitment
Period.
Rule 12. If a MUT Extended RTM Self-Commitment Period or a MDT Extended
RTM Self-Commitment Period resulted from Rule 8 through Rule 11
intersects with a Super RTM Self-Commitment Period that ends at the
end of the current Trading Day, and if the MUT/MDT Extended RTM Self-
Commitment Period is apart from a disjoint, nonadjacent and later Super
RUC Commitment Period in the RTM MDT Forthcoming Window by less
than the current MDT of the resource, the end-time of the MUT/MDT
Extended RTM Self-Commitment Period should be extended to the end of
the current Trading Day.
Rule 13. After this MDT extension process, the MUT Extended RTM Self-
Commitment Periods are referred to as MDT Extended RTM Self-
Commitment Periods regardless of whether any extension was made.
Rule 14. If the MDT Extended RTM Self-Commitment Periods generated by the
MDT extension process as described by Rule 8 through Rule 13 have
nonempty intersections, the MDT Extended RTM Self-Commitment
Periods having nonempty intersections should be merged.
The MDS Extended RTM Self-Commitment Periods for a resource in a Trading Day are
constructed in sequence as follows:
Rule 15. If there is any RTM Self-Commitment Period that starts at the beginning
of the Trading Day, or any RUC Commitment Period that starts at the
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beginning of the Trading Day, and the resource was “On” at the end of
the previous Trading Day, and if the total number of MDT Extended RTM
Self-Commitment Periods and their disjoint and nonadjacent Super RUC
Commitment Periods in the Trading Day is greater than (MDS+1) of the
resource, the MDT Extended RTM Self-Commitment Periods must be
extended in both directions in time iteratively to fill first the smallest time
gap with other disjoint and nonadjacent MDT Extended RTM Self-
Commitment Periods or Super RUC Commitment Periods that intersects
the same Super RTM Commitment Period until the number of MDT
Extended RTM Self-Commitment Periods and their disjoint and
nonadjacent Super RUC Commitment Periods in the Trading Day is equal
to (MDS+1).
Rule 16. If there is no RTM Commitment Period that starts at the beginning of the
Trading Day and there is no RUC Commitment Period that starts at the
beginning of the Trading Day, or the resource was “Off” at the end of the
previous Trading Day, and if the total number of MDT Extended RTM
Self-Commitment Periods and their disjoint and nonadjacent Super RUC
Commitment Periods in the Trading Day is greater than the MDS of the
resource, the MDT Extended RTM Self-Commitment Periods must be
extended in both directions in time to fill first the smallest gap in time with
the other disjoint and nonadjacent MDT Extended RTM Self-Commitment
Periods or Super RUC Commitment Periods that intersects the same
Super RTM Commitment Period until the number of MDT Extended RTM
Self-Commitment Periods and their disjoint and nonadjacent Super RUC
Commitment Periods in the Trading Day is equal to MDS.
Rule 17. After this MDS extension process, the MDT Extended RTM Self-
Commitment Periods are referred to as MDS Extended RTM Self-
Commitment Periods regardless of whether any extension was made.
The BCR RTM Self-Commitment Periods for a resource in a Trading Day are
constructed as follows:
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Rule 18. If an MDS Extended RTM Self-Commitment Period intersects with a
Super RUC Commitment Period, the intersection is excluded from the
MDS Extended RTM Self-Commitment Period; and the remaining portion
of the MDS Extended RTM Self-Commitment Period is the BCR RTM
Self-Commitment Period.
D.6.3. RTM Commitment Type Determination for Pump Storage Generator Resources in Pumping Mode
The general definitions (Def 1-4, and Def 6) in the previous section for generators also
apply to the pumping mode. The definitions and rules in this subsection apply to pump-
storage generator resources operating in pumping mode.
Def 20 A RTM Self-Commitment Period in pumping mode is a RTM Commitment Period that is resulted from energy self-schedules in pumping mode and their interaction with inter-temporal constraints imposed by MUT, MDT and MDS (in pumping mode) for the resource in the given period.8
Def 21 A Basic RTM Self-Commitment Period is a RTM Self-Commitment Period that is resulted directly from energy self-schedules in pumping mode (which is represented by negative quantities) without considering their interaction with inter-temporal constraints imposed by MUT, MDT and MDS (in pumping mode) for the resource in the given period.
Def 22 A MUT Extended RTM Self-Commitment Period in pumping mode is a RTM Self-Commitment Period in pumping mode that is resulted from one or more Basic RTM Self-Commitment Periods in pumping mode and their interaction with inter-temporal constraints imposed by MUT in pumping mode for the resource in the given period. The MUT used here is rounded up to the next 15-minute commitment interval if it is not already in multiples of 15-minutes. A Basic RTM Self-Commitment Period in pumping mode is referred to as a MUT Extended RTM Self-Commitment Period in pumping mode after the MUT Extension process even if no MUT extension is made.
Def 23 A MDT Extended RTM Self-Commitment Period in pumping mode is a RTM Self-Commitment Period in pumping mode that is resulted from one or more MUT Extended RTM Self-Commitment Period in pumping mode and their interaction with inter-temporal constraints imposed by MDT for the resource in the given period. The MDT used here is rounded up to the next 15-minute commitment interval if it is not already in multiples of 15-minutes. A MUT Extended RTM Self-Commitment Period in pumping mode is referred to as a MDT Extended RTM Self-
8 A pump-storage resource has separate MUT and MDS for operating in generating mode and pumping mode. A pump-storage resource has a single MDT for transitioning from generating mode to generating mode, from generating mode to pumping mode, from pumping mode to generating mode and from pumping mode to pumping mode.
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Commitment Period in pumping mode after the MDT Extension process even if no MDT extension is made.
Def 24 A MDS Extended RTM Self-Commitment Period in pumping mode is a RTM Self-Commitment Period in pumping mode that is resulted from one or more MDT Extended RTM Self-Commitment Period in pumping mode and their interaction with inter-temporal constraints imposed by MDS for the resource in pumping mode in the given period. A MDT Extended RTM Self-Commitment Period in pumping mode is referred to as a MDS Extended RTM Self-Commitment Period in pumping mode after the MDS Extension process even if no MDS extension is made.
Def 25 A BCR RTM Self-Commitment Period in pumping mode is a RTM Self-Commitment Period in pumping mode, which is resulted from a MDS Extended RTM Self-Commitment Period in pumping mode by excluding its intersections with IFM Commitment Periods in pumping mode for the resource in a given period. A MDS Extended RTM Self-Commitment Period in pumping mode is referred to as a BCR Extended RTM Self-Commitment Period in pumping mode after the BCR Exclusion process even if no truncation is made to exclude the intersection with any IFM Commitment Period in pumping mode.
Def 26 The BCR RTM Self-Commitment Periods in pumping mode, denoted by {SELFP}RTM, shall be the union of all BCR RTM Self-Commitment Periods in pumping mode, for a resource in a given time period.
Def 27 The BCR RTM Commitment Periods in pumping mode, denoted by {UCP}RTM, shall be the union of all RTM Commitment Periods in pumping mode excluding their intersections with IFM Commitment Periods in pumping mode for the resource in the given period.
Def 28 The BCR CAISO RTM Commitment Periods in pumping mode, denoted by {CAISOP}RTM, shall be the union of all BCR RTM Commitment Periods in pumping mode excluding their intersections with the BCR RTM Self-Commitment Periods in pumping mode, for a resource in a given time period.
Def 29 The RTM MUT Backtrack Window in pumping mode, is a period that has a configurable length and ends at the beginning of the current Trading Day. The configurable length is 2880 minutes (i.e., 2 days) by default. Note a pump-storage generator shall use two separately configurable RTM MUT Backtrack Windows; one for generating mode and the other for pumping mode.
Def 30 The RTM MDT Backtrack Window in pumping mode, is a period that has a configurable length and ends at the end of the current Trading Day. By default the configurable length is 2880 minutes (i.e., 2 days). Note a pump-storage generator shall have two separately configurable RTM MDT Backtrack Windows; one for generating mode and the other for pumping mode.
Def 31 The RTM MDT Forthcoming Window in pumping mode, is a period that has a configurable length and starts at the end of the current Trading Day. By default the configurable length is 1440 minutes (i.e., 1 day). Note a pump-storage generator shall use two separately configurable RTM MDT Forthcoming Windows; one for generating mode and the other for pumping mode.
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A RTM Self-Commitment Period in pumping mode will go through the following stages in
arriving at the final usable form for Bid Cost Recovery (BCR).
Basic MUT Extension MDT Extension MDS Extension BCR Exclusion
The Basic RTM Self-Commitment Periods in pumping mode for a resource in a given
period are constructed as follows:
Rule 19. If the resource is a pump-storage generating resource, identify all the
hours in which the resource has RTM energy self-schedules in pumping
mode in the given period.
Rule 20. Each set of consecutive hours identified in Rule 19, is a Basic RTM Self-
Commitment Period in pumping mode.
The MUT Extended RTM Self-Commitment Periods in pumping mode for a resource in a
given period are constructed using Rule 4 through Rule 7 except now the commitment
periods are in pumping mode and the RTM MUT Backtrack Window is in pumping mode
as defined by Def 29.
The MDT Extended RTM Self-Commitment Periods in pumping mode for a resource in a
Trading Day are constructed as follows:
Rule 21. If two disjoint and nonadjacent MUT Extended RTM Self-Commitment
Periods in pumping mode intersect with the same Super RTM
Commitment Period in pumping mode in the current Trading Day, and if
the two MUT Extended RTM Self-Commitment Periods in pumping mode
are apart from each other by less than the relevant MDT of the resource,
the two MUT Extended RTM Self-Commitment Periods in pumping mode
should be merged to form a MDT Extended RTM Self-Commitment
Period in pumping mode.
Rule 22. If a MUT Extended RTM Self-Commitment Period in pumping mode or a
MDT Extended RTM Self-Commitment Period in pumping mode resulted
from Rule 21 intersects the same Super RTM Commitment Period in
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pumping mode with a disjoint, nonadjacent and earlier Super IFM
Commitment Period in pumping mode in the RTM MDT Backtrack
Window in pumping mode, and if the MUT/MDT Extended RTM Self-
Commitment Period in pumping mode is apart from the Super IFM
Commitment Period by less than the current MDT of the resource, the
start-time of the MUT/MDT Extended RTM Self-Commitment Period in
pumping mode should be extended to the end-time of the Super IFM
Commitment Period in pumping mode or the beginning of the current
Trading Day.
Rule 23. If a MUT Extended RTM Self-Commitment Period in pumping mode or a
MDT Extended RTM Self-Commitment Period in pumping mode resulted
from Rule 21 and Rule 22 in the current Trading Day intersects the same
Super RTM Commitment Period in pumping mode with a disjoint,
nonadjacent and earlier MDS Extended RTM Self-Commitment Period in
pumping mode in the RTM MDT Backtrack Window in pumping mode,
and if the MUT/MDT Extended RTM Self-Commitment Period in pumping
mode is apart from the MDS Extended RTM Self-Commitment Period in
pumping mode by less than the current MDT of the resource, the start-
time of the MUT/MDT Extended RTM Self-Commitment Period in
pumping mode should be extended to the later of the end-time of the
MDS Extended RTM Self-Commitment Period in pumping mode or the
beginning of the current Trading Day.
Rule 24. If a MUT Extended RTM Self-Commitment Period in pumping mode or a
MDT Extended RTM Self-Commitment Period in pumping mode resulted
from Rule 21 through Rule 23 in the current Trading Day, intersects the
same Super RTM Self-Commitment Period in pumping mode with a
disjoint, nonadjacent and later Super IFM Commitment Period in pumping
mode in the current Trading Day, and if the MUT/MDT Extended RTM
Self-Commitment Period in pumping mode is apart from the Super IFM
Commitment Period in pumping mode by less than the current MDT of the
resource, the end-time of the MUT/MDT Extended RTM Self-Commitment
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Period in pumping mode should be extended to the start-time of the
Super IFM Commitment Period in pumping mode.
Rule 25. If a MUT Extended RTM Self-Commitment Period in pumping mode or a
MDT Extended RTM Self-Commitment Period in pumping mode resulted
from Rule 21 through Rule 24 in the current Trading Day, intersects with a
Super RTM Self-Commitment Period in pumping mode, which ends at the
end of the current Trading Day, and if the MUT/MDT Extended RTM Self-
Commitment Period in pumping mode is apart from a disjoint,
nonadjacent and later Super IFM Commitment Period in pumping mode in
the RTM MDT Forthcoming Window in pumping mode, by less than the
current MDT of the resource, the end-time of the MUT/MDT Extended
RTM Self-Commitment Period in pumping mode should be extended to
the end of the current Trading Day.
Rule 26. After this MDT extension process, the Basic RTM Self-Commitment
Periods in pumping mode are referred to as MDT Extended RTM Self-
Commitment Periods in pumping mode regardless of whether any
extension was made.
Rule 27. If the MDT Extended RTM Self-Commitment Periods in pumping mode
generated by the MDT extension process as described by Rule 21
through Rule 26 have nonempty intersections, the MDT Extended RTM
Self-Commitment Periods having nonempty intersections should be
merged.
The MDS Extended RTM Self-Commitment Periods in pumping mode for a resource in a
Trading Day are constructed as follows:
Rule 28. If there is any RTM Self-Commitment Period in pumping mode that starts
at the beginning of the Trading Day, or any IFM Commitment Period in
pumping mode that starts at the beginning of the Trading Day; and the
resource was “On” in pumping mode at the end of the previous Trading
Day, and if the total number of MDT Extended RTM Self-Commitment
Periods in pumping mode and their disjoint and nonadjacent Super IFM
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Commitment Periods in pumping mode in the Trading Day is greater than
(MDS+1) of the resource, the MDT Extended RTM Self-Commitment
Periods in pumping mode must be extended in both directions in time
iteratively to fill first the smallest time gap with other disjoint and
nonadjacent MDT Extended RTM Self-Commitment Periods in pumping
mode or Super IFM Commitment Periods in pumping mode that intersects
the same Super RTM Commitment Period in pumping mode until the
number of MDT Extended RTM Self-Commitment Periods in pumping
mode and their disjoint and nonadjacent Super IFM Commitment Periods
in pumping mode in the Trading Day is equal to (MDS+1);
Rule 29. If there is no RTM Commitment Period in pumping mode that starts at the
beginning of the Trading Day and there is no IFM Commitment Period in
pumping mode that starts at the beginning of the Trading Day, or the
resource was not in pumping mode at the end of the previous Trading
Day, and if the total number of MDT Extended RTM Self-Commitment
Periods in pumping mode and their disjoint and nonadjacent Super IFM
Commitment Periods in pumping mode in the Trading Day is greater than
the relevant (i.e., pump) MDS of the resource, the MDT Extended RTM
Self-Commitment Periods in pumping mode must be extended in both
directions in time to fill first the smallest gap in time with the other disjoint
and nonadjacent MDT Extended RTM Self-Commitment Periods in
pumping mode or Super IFM Commitment Periods in pumping mode that
intersects the same Super RTM Commitment Period in pumping mode
until the number of MDT Extended RTM Self-Commitment Periods in
pumping mode and their disjoint and nonadjacent Super IFM
Commitment Periods in pumping mode in the Trading Day is equal to
relevant (i.e., pump) MDS.
Rule 30. After this MDS extension process for pump storage generating resources
in pumping mode, the MDT Extended RTM Self-Commitment Periods in
pumping mode are referred to as MDS Extended RTM Self-Commitment
Periods in pumping mode regardless of whether any extension was
made.
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The BCR RTM Self-Commitment Periods in pumping mode for a resource in a Trading
Day are constructed as follows:
Rule 31. If a MDS Extended RTM Commitment Period in pumping mode intersects
with a Super IFM Commitment Period in pumping mode, the intersection
is excluded from the MDS Extended RTM Commitment Period in pumping
mode; the remaining portion of the MDS Extended RTM Commitment
Period in pumping mode is the BCR RTM Self-Commitment Period in
pumping mode.
The BCR for Pump Shut-Down Cost will not be based on the BCR RTM Self-
Commitment Periods because the BCR RTM Self-Commitment Periods indicate that the
unit is in pumping mode because of self-schedules. For determination of the eligibility for
BCR of Pump Shut-Down Cost, one needs to determine whether the unit is transitioning
out of the pumping mode solely because of the unit’s own decision and not CAISO’s
decision. Therefore, whether a RTM pump shut-down, is considered as "self
commitment", is determined according to the following rules.
Rule 32. If the RTM Commitment Periods in pumping mode in a Trading Day
indicates a Pump Shutdown (i.e., end of a Super RTM Commitment
Period in pumping mode), and the unit does not have any Pump Cost Bid
Component or Pumping Self-Schedule Bid Component for the immediate
hour after the RTM Pump Shutdown, the RTM Pump Shutdown is BCR
RTM Self-Commitment.
Rule 33. If the RTM Commitment Periods in pumping mode in a Trading Day
indicates a Pump Shutdown (i.e., end of a Super RTM Commitment
Period in pumping mode), and the unit has a Basic RTM Self-
Commitment Period in generating mode starting within the relevant MDT
after the RTM Pump Shutdown, the RTM Pump Shutdown is BCR RTM
Self-Commitment.
D.6.4. Examples for RTM Commitment Type Determination
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Example 20 – Generator Resource RTM Commitment type determination Rule # 4
(i) MUT
In this example, the following assumptions are made as shown in Figure .
MUT = 6 hours
There resource was “On” in the period [23, 24) of the previous Trading Day
Basic RTM Self-Commitment Period: [0, 4) in the current Trading Day.
Super RTM Commitment Period: [0, 8) in the Current Trading Day.
According to Rule #4(i), since the length of the Basic RTM Self-Commitment Period (4
hours) is less than the MUT of the resource minus the ‘On time” (5 hours), the Self-
Commitment period must be extended to the minimum of 5 hours. This extension
process results in the MUT Extended RTM Self-Commitment Period [0, 5). This is
illustrated in Figure 20.
4 50
MUT extended RTM Self Commitment
period
Basic RTM Self-Commitment
period
MUT = 6h
ON-TIME = 1h
MUT - ON-TIME = 5h
Extend to 5h
1
24Super RTM Commitment
Period
8
Figure 20: Illustration of Rule #4(i)
Example 21 – Generator Resource RTM Commitment type determination Rule # 4
(ii) MUT
In this example, the following assumptions are made as shown in Figure 21.
MUT = 6 hours
The resource was OFF at the end of the previous Trading Day
Basic RTM Self-Commitment Period: [0, 4) in the current Trading Day.
Super RTM Commitment Period: [0, 10) in the Current Trading Day.
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According to Rule #4(ii), since the length of the Basic RTM Self-Commitment Period (4
hours) is less than the MUT of the resource (6 hours), the Self-Commitment period must
be extended by 2 hours to the minimum of 6 hours. This extension process results in the
MUT Extended RTM Self-Commitment Period [0, 6). This is illustrated in Figure 21.
4 60
MUT extended RTM Self-Commitment
period
Basic RTM Self-Commitment
period
24
MUT = 6h
Extend to 6h
10
Super RTM Commitment
Period
Figure 21: Illustration of Rule #4(ii)
Example 22 – Generator Resource RTM Commitment type determination Rule # 4
(iii) MUT
In this example, the following assumptions are made as shown in Figure 2.
MUT = 8 hours
Basic RTM Self-Commitment Period: [3, 7) in the current Trading Day.
On Time evaluated at the beginning of the Basic RTM Self-Commitment Period is
2 hours.
Super RTM Commitment Period: [1, 11) in the Current Trading Day.
According to Rule #4(iii), since the length of the Basic RTM Self-Commitment Period (4
hours) is less than the MUT of the resource minus the “On Time” evaluated at the
beginning of the Basic RTM Self-Commitment Period (6 hours), the Self-Commitment
period must be extended by 2 hours to the minimum of 6 hours. This extension process
results in the MUT Extended RTM Self-Commitment Period [3, 9). This is illustrated in
Figure 22.
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3 7
0
MUT extended RTM Self
Commitment period
Basic RTM Self Commitment
period
MUT = 8h
ON-TIME = 2h
MUT - ON-TIME = 6h
Extend to 6h
241 9Super RTM Commitment
Period
Figure 22: Illustration of Rule #4(iii)
Example 23 – Generator Resource RTM Commitment type determination Rule # 4
(iv) MUT
In this example, the following assumptions are made as shown in Figure .
MUT = 8 hours
Basic RTM Commitment Period: [7, 14) which is also a Super RTM Commitment
Period in the current Trading Day.
On Time evaluated at the beginning of the Basic RTM Commitment Period is
zero.
According to Rule #4(iv), even though the length of the commitment period is less than
the MUT of the resource minus the “On time”, the Basic RTM Self-Commitment Period is
not extended, which results in a MUT Extended RTM Self-Commitment Period [7, 14)
even though no extension was made. The reason that no extension is made is because
the Basic RTM Commitment Period itself is a Super RTM Commitment Period; the MUT
was not observed either because the market participants bids were infeasible as to MUT
or the RTM application failed to comply with the MUT. The MQS as a post process
cannot extend the Basic Self-Commitment Period into intervals where the unit is “Off.”
This is illustrated in Figure 23.
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14
0
MUT extended RTM Self
Commitment period
Basic RTM SC period that is
also a Super RTM Self
Commitment period
MUT = 8h
ON-TIME = 1h
247
Figure 23: Illustration of Rule #4(iv)
Example 24 – Generator Resource RTM Commitment type determination Rule 5Rule 5 MUT
In this example, the following assumptions are made as shown in Figure .
MUT = 12 hours
On-time by 6/11/07 18:00 is 240 minutes (i.e., 4 hours)
Super RTM Commitment Period [6/11/07 18:00, 6/11/07 24:00) in the RTM MUT Backtrack Window
MDS Extended Self-Commitment Period [6/11/07 21:00, 6/11/07 24:00)
Super RTM Commitment Period [00:00, 06:00) in the Current Trading Day
(6/12/07)
According to Rule 5, since the length of the Super RTM Commitment period in the
Backtrack Window, which is 6 hours, is less than the (MUT - On-time) by X = 120
minutes or 2 hours, a MUT Extended Commitment period [00:00, 02:00) is defined in the
current Trading Day. The MUT Extended Commitment period [00:00, 02:00) is a portion
of the MUT Extended RTM Self-Commitment period [6/11/07 21:00, 6/12/07 02:00) that
fits in the current Trading Day. This is illustrated in Figure 24.
0
MUT extended RTM Self- Commitment
period
MUT = 12h
ON-TIME (s) = 240 (mins)
24
1800 06002100 0200
s m ex
Backtrack Window
Figure 24: Illustration of Rule 5
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Example 25 – Generator Resource RTM Commitment type determination Rule
8Rule 8 MDT
In this example, the following assumptions are made as shown in Figure .
MDT = 9 hours
Super RTM Commitment Period: [0, 24) in the current Trading Day.
Disjoint and nonadjacent MUT Extended RTM Self-Commitment Periods : [0, 9)
and [14, 23)
According to Rule 8, since the two MUT Extended RTM Self-Commitment Periods are
apart from each other by less than the MDT of the resource, the two MUT extended
RTM Self-Commitment Periods are merged to form a MDT Extended RTM Self-
Commitment Period [0, 23). This is illustrated in Figure 25.
MUT Extended RTM Self-
Commitment period 1
L
9 140
MDT = 9h
L = 5h
23
MUT Extended Self-
Commitment period
2
MDT Extended RTM Self-Commitment periodSuper RTM
commitment
period
Figure 25: Illustration of Rule 8
Example 26– Generator Resource RTM Commitment type determination Rule
9Rule 9 MDT
In this example, the following assumptions are made as shown in Figure .
MDT = 9 hours
MUT Extended RTM Self-Commitment Period: [05:00, 12:00) in the current
Trading Day (6/12/07).
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Super RUC Commitment Period: [6/11/07 14:00, 6/11/07 21:00) in the RTM MDT
Backtrack Window
Super RTM Commitment Period: [6/11/07 14:00, 6/12/07 12:00)
According to Rule 9, since the MUT Extended RTM Self-Commitment Period is apart
from the disjoint, nonadjacent and earlier Super RUC Commitment Period by less than
the MDT of the resource, the start-time of the MUT Extended RTM Self-Commitment
Period is extended to the beginning of the Current Trading Day. This extension process
results in a MDT Extended RTM Self-Commitment Period [6/12/07 00:00, 6/12/07
12:00). This is illustrated in Figure 26.
Super RUC
Commitment
Period
5 120
MDT = 9h
21
MUT Extended
Self-
Commitment
period
MDT Extended RTM Self-
Commitment period
14
Super RTM
Commitment Period
Figure 26: Illustration of Rule 9
Example 27– Generator Resource RTM Commitment type determination Rule
10Rule 10 MDT
In this example, the following assumptions are made as shown in Figure .
MDT = 9 hours
MUT Extended RTM Self-Commitment Period: [5, 12) in the current Trading Day
(6/12/07).
A disjoint, nonadjacent and earlier MDS Extended RTM Self-Commitment Period:
[6/11/07 14:00, 6/11/07 21:00) in the RTM MDT Backtrack Window
Super RTM Commitment Period: [6/11/07 15:00, 6/12/07 20:00) which is
intersected by both the MUT Extended RTM Self-Commitment period and the
MDS Extended RTM Self-Commitment period.
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According to Rule 10, since the MUT Extended RTM Self-Commitment Period is apart
from the MDS Extended RTM Self-Commitment Period by less than the current MDT of
the resource, the start time of the MUT Extended Self-Commitment Period is extended
to the beginning of the current trading day. This extension process results in a MDT
Extended RTM Self-Commitment Period [6/12/07 00:00, 6/12/07 12:00). This is
illustrated in Figure 27.
MDS
Extended
RTM Self-
Commitment
period
5 120
MDT = 9h
21
MUT Extended
Self-
Commitment
period
MDT Extended RTM Self-
Commitment period
14
Super RTM
commitment period
Figure 27: Illustration of Rule 10.
Example 28– Generator Resource RTM Commitment type determination Rule
11Rule 11 MDT
In this example, the following assumptions are made as shown in Figure .
MDT = 9 hours
MUT Extended RTM Self-Commitment Period: [4, 12) in the current Trading Day.
A disjoint, nonadjacent and later Super RUC Commitment Period in the Current
Trading Day: [20, 24)
Super RTM Self-Commitment Period: [4, 24) which is intersected by both the
MUT Extended RTM Self-Commitment period and the Super RUC Commitment
period detailed previously.
According to Rule 11, since the MUT Extended RTM Self-Commitment Period is apart
from the Super RUC Commitment Period by less than the current MDT of the resource,
the end time of the MUT Extended Self-Commitment Period is extended to the start-time
of the Super RUC Commitment Period. This extension process results in a MDT
Extended RTM Self-Commitment Period [4, 20). This is illustrated in Figure 28.
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4 200
MDT = 9h
MUT Extended RTM Self-
Commitment period
12
Super RTM
commitment period
Super RUC
Commitment
period
MDT Extended RTM Self-Commitment
period
0
Figure 28: Illustration of Rule 11
Example 29 – Generator Resource RTM Commitment type determination Rule
12Rule 12 MDT
In this example, the following assumptions are made as shown in Figure
MDT = 9 hours
MUT Extended RTM Self-Commitment Period: [6/11/07 06:00, 6/11/07 21:00) in
the current Trading Day.
A disjoint, nonadjacent and later Super RUC Commitment Period in the RTM
MDT Forthcoming Window: [6/12/07 02:00, 6/12/07 08:00)
Super RTM Self-Commitment Period: [6/11/07 06:00, 6/11/07 24:00).
According to Rule 12, since the MUT Extended RTM Self-Commitment Period is apart
from the Super RUC Commitment Period by less than the current MDT of the resource,
the end time of the MUT Extended Self-Commitment Period is extended to the end of
the current Trading Day. This extension process results in a MDT Extended RTM Self-
Commitment Period [6/11/07 06:00, 6/11/07 24:00). This is illustrated in Figure 29.
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6 210
MDT = 9h
8
MUT Extended RTM Self-
Commitment period
17
Super RTM
commitment period
Super RUC
Commitment
period
MDT Extended RTM Self-Commitment
period
2
Figure 29: Illustration of Rule 12
Example 30 – Generator Resource RTM Commitment type determination Rule
15Rule 15 MDS
In this example, the following assumptions are made as shown in Figure
MDS = 1
The resource was ON at the end of the previous Trading Day.
Super RTM Commitment Period: [0, 24) in the current Trading Day.
Super RUC Commitment Period: [0, 5) in the current Trading Day.
MDT Extended RTM Self-Commitment Period: [7, 14) in the current Trading Day.
MDT Extended RTM Self-Commitment Period: [17, 21) in the current Trading
Day.
According to Rule 15, since the total number of MDT Extended RTM Self Commitment
Periods and their disjoint and nonadjacent Super RUC Commitment Periods in the same
trading Day is 3 which is more than (MDS + 1) = 2, the MDT Extended RTM Self-
Commitment Period [7, 14) is extended to fill the smallest time gap [5, 7) with the
disjoint and nonadjacent Super RUC Commitment Period [0, 5) that intersect the same
Super RTM commitment Period. After this extension process, the number of MDT
Extended RTM Self-Commitment Periods or Super RUC Commitment Periods and their
disjoint and nonadjacent Super RUC Commitment Periods in the Trading Day is equal to
( MDS + 1) = 2.This extension process results in a MDS Extended Self-Commitment
Period [5, 14). This is illustrated in Figure 30.
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Figure 30: Illustration of Rule 15.
Example 31 – Generator Resource RTM Commitment type determination Rule 16Rule 16 MDS
In this example, the following assumptions are made as shown in Figure .
MDS = 2
The resource was OFF at the end of the previous Trading Day.
Super RTM Commitment Period: [0, 24) in the current Trading Day.
Super RUC Commitment Period: [2, 7) in the current Trading Day.
MDT Extended RTM Self-Commitment Period: [9, 15) in the current Trading Day.
Super RUC Commitment Period: [18, 21) in the current Trading Day.
According to Rule 16, since the total number of MDT Extended RTM Self Commitment
Periods and their disjoint and nonadjacent Super RUC Commitment Periods in the same
trading Day is 3 which is more than the MDS (which is 2) of the resource, the MDT
Extended RTM Self-Commitment Period is extended to fill the smallest time gap [7, 9)
with the disjoint and nonadjacent Super RUC Commitment Period that intersect the
same Super RTM commitment Period [2, 7) to bring the number of MDT Extended RTM
Self-Commitment Periods and their disjoint and nonadjacent Super RUC Commitment
Periods in the Trading Day to MDS (which is 2). This extension process results in a MDS
Extended Self-Commitment Period [7, 15). This is illustrated in Figure 31.
MDT Extended
5 70
MDS = 1
( MDS + 1 ) = 2
24211714
MDT Ext.RUC
MDS Extended period
Super RTM
commitment
period
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MDT Extended
7 92
MDS = 2
24211815
RUCRUC
MDS Extended period
Super RTM
commitment
period
Figure 31: Illustration of Rule 16.
Example 32 – Generator Resource RTM Commitment type determination Rule 18 BCR
In this example, the following assumptions are made as shown in Figure .
MDS Extended RTM Self-Commitment Period: [0, 15) in the current Trading Day.
Super RUC Commitment Period: [12, 21) in the current Trading Day.
According to Rule 18, since the MDS Extended RTM Commitment Period intersects with
a Super RUC Commitment Period, the intersection is excluded from the MDS Extended
RTM Commitment Period and the remaining MDS Extended RTM Commitment Period is
the BCR RTM Self-Commitment Period i.e. [0, 12). This is illustrated in Figure 32.
BCR RTM SC period
0 2112 15
MDS extended commitment period
Overlap
Super RUC period
Figure 32. Illustration of Rule 18.
Example 33 - BCR for Pump Shutdown Cost Determination, Rule 32Rule 32 BCR
In this example, a Super RTM Commitment Period in pumping mode comes to an end
and there is no Pump Cost Bid Component or Pump Self-Schedule Bid Component for
the immediate hour after the Pump shut-down. Therefore, the Pump shut-down is a BCR
RTM Self-Commitment. See Figure 33 for an illustration. This is illustrated in Figure 33.
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0
244 12
Super RTM Commitment
Period in pumping mode
Pump Shutdown is BCR
RTM Self-Commitment
Figure 33: Illustration of Rule # 32
Example 34- BCR for Pump Shutdown Cost Determination, Rule 33Rule 33 BCR
In this example, a Super RTM Commitment Period in pumping mode comes to an end
and the unit has a Basic RTM Self-Commitment Period in generating mode starting
within the MDT after the pump shutdown. Therefore, the Pump shut-down is a BCR RTM
Self-Commitment. This is illustrated in Figure 34.
0
244 12
Super RTM Commitment
Period in pumping mode
Pump Shutdown is BCR
RTM Self-Commitment
MDT = 5
16 21
Basic RTM Self-Commitment
Period in generating mode
Figure 34: Illustration for Rule #33
D.7. IFM/RUC/RTM Start-up Cost/Pump Shut-down Cost and Minimum Load Cos/Pumping Cost Determination
After the determination of ISO commitment versus self commitment period, the eligible
Start-up Cost (SUC), eligible pump shut-down cost (PSDC), the eligible Minimum Load
Cost (MLC) and the eligible Pumping Cost (PC) for each CAISO committed interval in
either IFM, RUC, or RTM will need to be calculated. As a by-product, the SUC/PSDC
and MLC/PC eligibility flags for IFM, RUC, and RTM. The eligibility flag is a Y/N flag.
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The determination of commitment cost will include the generating resources including
Pumped-Storage Hydro Units as well as the participating loads (pumps that are
dispatchable) and tie generators.
D.7.1. Data Requirements
Inputs
-- The ISO versus self commitment periods are determined by business rules described
in sections D2 to D6.
ISO Commitment Period of IFM, RUC, RTM
Hourly in IFM, RUC, 15 minutes in RTM;
All generators except Pumped-Storage Hydro Units can be committed in on-line
or off-line in IFM, RUC, RTM;
All Pumped-Storage Hydro Units can be committed in pumping mode, generation
mode or offline mode in IFM, RUC, RTM except there is no pumping mode
commitment in RUC;
All Participating Loads can be committed in pumping mode or offline mode in IFM
and RTM.
Self-Commitment Period of IFM and RTM (no self commit in RUC)
Hourly in IFM, 15 minutes in RTM;
Same rules apply regarding various resources as ISO Commitment except that
there is no self-commit in RUC.
Start-up Time (All Generators)
Minimum Load Cost (All Generators)
Hourly $ value per resource
Startup Cost (All Generators)
$ value per startup
Pumping Cost (Pumped-Storage Hydro Units and Participating Loads)
Hourly $ value per resource
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Pump Shut-down cost (Pumped-Storage Hydro Units and Participating Loads)
$ value per pump shut-down
Real-time Start-up/Shut-down Instructions including exceptional dispatch commitment
instructions
RUC Start-up Instructions
Outputs
BCR Eligible SUC ($) per resource, per settlement interval, per market type
BCR Eligible MLC ($) per resource, per settlement interval, per market type
BCR Eligible PSDC ($) per resource, per settlement interval, per market type
BCR Eligible PC ($) per resource, per settlement interval, per market type
SUC Eligibility flag per resource, per settlement interval, per market type
PSDC Eligibility flag per resource, per settlement interval, per market type
MLC Eligibility flag per resource, per settlement interval, per market type
PC Eligibility flag per resource, per settlement interval, per market type
D.7.2. Some Background Information
Following description focuses on explanation of the difference between generation and
pumping.
Applicability
A start-up cost/minimum load cost settlement applies to generators and Pumped-
Storage Hydro Units in generation mode. Those resources can be committed in IFM,
RUC or RTM.
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A shutdown cost/pumping cost settlement applies to Pumped-Storage Hydro Units in
pumping mode and Participating Load (Pumps). Those resources can be committed in
IFM or RTM, not RUC.
Minimum Load Cost VS Pumping Cost
The concept of pumping cost is the same as minimum load cost except that the resource
runs at an energy consumption level. The business rules for determining the eligibility for
pumping load cost is the same as for minimum load cost. In the following business rules,
we will use the minimum load cost as the term representing both minimum load cost in
generation mode and pumping cost in pumping mode.
Start-Up Cost VS Shut down Cost
A start-up cost settlement applies to generators and Pumped-Storage Hydro Units in
generation mode. Those resources can be committed in IFM, RUC or RTM.
A shutdown cost settlement ONLY applies to Pumped-Storage Hydro Units in pumping
mode and Participating Load. In the following description, we will simply use the term
“Pump” to refer to a participating load (a real pump) or a Pumped-Storage Hydro Unit in
pumping mode. Pump shutdown cost is used to recover the cost associated with those
resources when they are committed to be shutdown by CAISO while they are in pumping
mode.
A shutdown of a pump differs from a startup of a generator in the following perspective:
1.A shutdown of Pump happens immediately and hence the “shutdown time period”
concept will not be applied;
2.The concept of minimum load cost to pump is really the pumping cost as described
before;
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3.There is no pump shutdown in RUC and hence there is no need to deal with RUC
shutdown cost.
A shutdown of a pump is similar to a startup of a generator in the following perspective:
1. A pump is associated with the shutdown cost as part of the bid just like the startup
cost. However, a shutdown cost is only one single value while a startup cost is an up to
three tiers of step functions based on cooling time;
2. CAISO only pays the pump shutdown due to CAISO commitment reason. CAISO will
not pay shutdown cost if the pump is self-committed.
Some clarifications related to Shut-down:
DA Shut-down:
For a pump, when we "turn off" a pump in DA, we do NOT explicitly have a pump Shut-
down instruction. The fact that a pumping mode hour followed by an offline mode hour
will implicitly tell that the pump was determined to be "shut down" in DA;
For a pumping storage resource, it is similar.
RT Shut-down:
For a pump, when we "turn off" a pump in RT, we do EXPLICITLY have a pump Shut-
down instruction;
For a Pumped-Storage Hydro Unit, it is the same except that it is also possible we see a
15-minute in pumping mode followed by a 15-minute interval in generation or off-line
mode.
Interim Participating Load modeling in MRTU release 1:
Since we model some of the pumps using a non-participating load and a pseudo-
generating resource in MRTU release 1, for these pumps, the pumping cost will be
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modeled as the minimum load cost of the pseudo-generator and the pump shutdown
cost will be modeled as the startup cost of the pseudo-generator.
Exceptional Dispatch Shut-down:
It is possible to issue an OOS (exceptional dispatch) commitment instruction to Shut-
down a pump in RTM.
D.7.3. Business Rules for Cost Calculation
For all start-up and shut-downs, CAISO will check the meter data to determine whether
this actually happens before applying appropriate BCR amount. This logic is described in
BPM section for settlement. Following rules describe how to calculate the “potential”
eligibility and $ amount for evaluation before comparison of the revenue meter data. For
Multi-Stage Generating Resources, the following rules apply at the MSG Configuration
level, and do so in conjunction with the Multi-Stage Generating Resource specific rules
described in section D7.4.
In following rules, when commitment periods are mentioned, it is always referring to ISO
commitment period. A self commitment period will be specified mentioned as self
commitment period.
Business Rules for IFM Start-Up Cost
The IFM Start-Up Cost for any IFM Commitment Period shall equal to the Start-Up Costs
submitted by the Scheduling Coordinator to the CAISO for the IFM divided by the
number of Settlement Intervals in the applicable IFM Commitment Period. For each
Settlement Interval, only the IFM Start Cost in a CAISO IFM Commitment Period is
eligible for Bid Cost Recovery. The following rules shall apply sequentially to qualify the
IFM Start-Up Cost in an IFM Commitment Period:
1. The IFM Start-Up Cost for an IFM Commitment Period shall be zero if it is overlapped
with or adjunction to an IFM Self-Commitment Period.
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2. The IFM Start-Up Cost for an IFM Commitment Period shall be zero if the Bid Cost
Recovery Eligible Resource is manually pre-dispatched under an RMR Contract prior to
the Day-Ahead Market or the resource is flagged as an RMR Dispatch in the Day-Ahead
Schedule in the Day-Ahead Market anywhere within the applicable IFM Commitment
Period.
3. The IFM Start-Up Cost for an IFM Commitment Period shall be zero if there is no
actual Start-Up at the start of the applicable IFM Commitment Period because the IFM
Commitment Period is the continuation of an IFM or RUC Commitment Period from the
previous Trading Day.
4. If an IFM Start-Up is terminated in the Real-Time within the applicable IFM
Commitment Period through an Exceptional Dispatch Shut-Down Instruction issued
while the Bid Cost Recovery Eligible Resource was Starting Up, the IFM Start-Up Cost
for that IFM Commitment Period shall be prorated by the ratio of the Start-Up time before
termination over the total IFM Start-Up time.
5. If a Short Start unit is commitment by the IFM and is started up in the Real-time
Market after the start of and before the end of the IFM Commitment Period, the IFM Start
Up cost shall be qualified. Any subsequent Start-Ups pursuant to a Shut-Down
Instruction the Short-Start Unit receives in the Real-Time Market that falls within the IFM
Commitment Period, the Start-Up Costs will be qualified as an RTM Start-Up Cost.
Business Rules for IFM Minimum Load Cost/Pumping Cost
The Minimum Load Cost for the applicable Settlement Interval shall be the Minimum
Load Cost/Pumping Cost submitted to the CAISO in the IFM divided by the number of
Settlement Intervals in a Trading Hour. For each Settlement Interval, only the IFM
Minimum Load Cost in a CAISO IFM Commitment Period is eligible for Bid Cost
Recovery.
The IFM Minimum Load Cost/Pumping Cost for any Settlement Interval is zero if:
1. The Settlement Interval is in an IFM Self Commitment Period for the Bid Cost
Recovery Eligible Resource;
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2. The Bid Cost Recovery Eligible Resource is manually pre-dispatched under an RMR
Contract prior to the Day-Ahead Market or the resource is flagged as an RMR Dispatch
in the Day-Ahead Schedule for the applicable Settlement Interval;
Business Rules for RUC Start-Up Cost
The RUC Start-Up Cost for any Settlement Interval in a RUC Commitment Period shall
consist of Start-Up Cost of the Bid Cost Recovery Eligible Resource submitted to the
CAISO for the applicable RUC Commitment Period divided by the number of Settlement
Intervals in the applicable RUC Commitment Period. For each Settlement Interval, only
the RUC Start Cost in a CAISO RUC Commitment Period is eligible for Bid Cost
Recovery. The following rules shall be applied in sequence and shall qualify the RUC
Start-Up Cost in a RUC Commitment Period:
1. The RUC Start-Up Cost for a RUC Commitment Period is zero if it is overlapped with
or adjunction to an IFM Commitment Period within that RUC Commitment Period.
2. The RUC Start-Up Cost for a RUC Commitment Period is zero if the Bid Cost
Recovery Eligible Resource is manually pre-dispatched under an RMR Contract prior to
the Day-Ahead Market or is flagged as an RMR Dispatch in the Day-Ahead Schedule
anywhere within that RUC Commitment Period.
3. The RUC Start-Up Cost for a RUC Commitment Period is zero if there is no RUC
Start-Up at the start of that RUC Commitment Period because the RUC Commitment
Period is the continuation of an IFM or RUC Commitment Period from the previous
Trading Day.
.
4. If a RUC Start-Up is terminated in the Real-Time within the applicable RUC
Commitment Period through an Exceptional Dispatch Shut-Down Instruction issued
while the Bid Cost Recovery Eligible Resource is starting up the, RUC Start-Up Cost is
prorated by the ratio of the Start-Up Time before termination over the RUC Start-Up
Time.
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5. If a Short Start unit is committed by CAISO in Real Time as a result of its RUC
capacity but does not have a Day Ahead Schedule, the commitment type will also be
considered a CAISO RUC commitment.
6. If a Short Start unit is commitment by the RUC and is started up in the Real-time
Market after the start of and before the end of the RUC Commitment Period, the RUC
Start Up cost shall be qualified. Any subsequent Start-Ups pursuant to a Shut-Down
Instruction the Short-Start Unit receives in the Real-Time Market that falls within the
RUC Commitment Period, the Start-Up Costs will be qualified as an RTM Start-Up Cost.
Business Rules for RUC Minimum Load Cost
-- No Pumping Cost will be incurred in RUC
The Minimum Load Cost for the applicable Settlement Interval shall be the Minimum
Load Cost of the Generating Bid Cost Recovery Eligible Resource divided by the
number of Settlement Intervals in a Trading Hour. For each Settlement Interval, only the
RUC Minimum Load Cost in a CAISO RUC Commitment Period is eligible for Bid Cost
Recovery. The RUC Minimum Load Cost for any Settlement Interval is zero if:
1. The Bid Cost Recovery Eligible Resource is manually pre-dispatched under an RMR
Contract or the resource is flagged as an RMR Dispatch in the Day-Ahead Schedule in
that Settlement Interval;
2. The applicable Settlement Interval is included in an IFM Commitment Period.
Business Rules for RTM Start-Up Cost
For each Settlement Interval of the applicable Real-Time Market Commitment Period,
the Real-Time Market Start-Up Cost shall consist of the Start-Up Cost of the Generating
Bid Cost Recovery Eligible Resource submitted to the CAISO for the Real-Time Market
divided by the number of Settlement Intervals in the applicable Real-Time Market
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Commitment Period. For each Settlement Interval, only the Real-Time Market Start-Up
Cost in a CAISO Real-Time Market Commitment Period is eligible for Bid Cost
Recovery. The following rules shall be applied in sequence and shall qualify the Real-
Time Market Start-Up Cost in a Real-Time Market Commitment Period:
1. The Real-Time Market Start-Up Cost is zero if it is overlapped with or adjunction to a
Real-Time Market Self-Commitment Period.
2. The Real-Time Market Start-Up Cost is zero if the Bid Cost Recovery Eligible
Resource has been manually pre-dispatched under an RMR Contract or the resource is
flagged as an RMR Dispatch in the Day-Ahead Schedule or Real-Time Market anywhere
within that Real-Time Market Commitment Period.
3. The Real-Time Market Start-Up Cost is zero if there is no Real-Time Market Start-Up
at the start of that Real-Time Market Commitment Period because the Real-Time Market
Commitment Period is the continuation of an IFM or RUC Commitment Period from the
previous Trading Day.
4. If a Real-Time Market Start-Up is terminated in the Real-Time within the applicable
Real-Time Market Commitment Period through an Exceptional Dispatch Shut-Down
Instruction issued while the Bid Cost Recovery Eligible Resource is starting up the Real-
Time Market Start-Up Cost is prorated by the ratio of the Start-Up Time before
termination over the Real-Time Market Start-Up Time.
Business Rules for RTM Minimum Load Cost/Pumping Cost
The Real-Time Market Minimum Load Cost is the incremental Minimum Load
Cost/Pumping Cost of the Bid Cost Recovery Eligible Resource submitted to the CAISO
for the Real-Time Market divided by the number of Settlement Intervals in a Trading
Hour. The Real-Time Market Minimum Load Cost/Pumping Cost for any Settlement
Interval is zero if:
1. The Settlement Interval is included in a Real-Time Market Self Commitment period for
Bid Cost Recovery Eligible Resource;
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2. The Bid Cost Recovery Eligible Resource has been manually dispatched under an
RMR contract or the resource has been flagged as an RMR Dispatch in the Day-Ahead
Schedule or the Real-Time Market in that Settlement Interval;
3. That Settlement Interval is included in an IFM or RUC Commitment Period in
generation mode for MLC or pumping mode for PC
The Real-Time Market Minimum Load Cost for any Settlement interval is negative if:
1. The Resource is economically de-committed in Real-Time Market for periods the
resource has an IFM or RUC Commitment period
Business Rules for IFM Shut-down Cost
An IFM Shut-down Period is defined as the hour in which a pump Shut-down is to occur.
The Shut-down is implied and therefore the IFM Shut-down Period will be the immediate
hour following the last commitment hour in pumping mode before the “switch”;
The IFM Shut-down Cost for a settlement interval within an IFM Shut-down Period shall
equal to the Shut-down Costs submitted by the Scheduling Coordinator to the CAISO for
the IFM divided by the number of Settlement Intervals in the IFM Shut-down Period. For
each Settlement Interval, only the IFM Shut-down Cost in an IFM Shut-down Period is
eligible for Bid Cost Recovery. The following rules shall apply sequentially to qualify the
IFM Shut-down Cost in an IFM Shut-down Period:
1. The IFM Shut-down Cost for an IFM Shut-down Period shall be zero if it is
followed by an IFM or RT self commitment period in generation mode or offline
mode;
2. The IFM Shut-down Cost for an IFM Shut-down Period shall be zero if it is due to
a SLIC outage;
3. The IFM Shut-down Cost for an IFM Shut-down Period shall be zero if the Shut-
down is delayed by the Real-Time Market past the IFM Shut-down Period in
question or cancelled by the Real-Time Market before the shut-down process
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has started. This can be detected by having the same hour in DA pumping mode
and RT Generation/Off-line, Or DA pumping mode followed by Real-time
pumping in the following hour.
Business Rules for RTM Shut-down Cost
A RTM Shut-down Period is defined as the hour within which a real-time shut down
instruction will occur if the shutdown time is within the hour, Or the immediate hour
following the instruction if the shutdown time is at an hourly boundary.
The RTM Shut-down Cost for a settlement interval within a RTM Shut-down Period shall
equal to the Shut-down Costs submitted by the Scheduling Coordinator to the CAISO for
the RTM divided by the number of Settlement Intervals in the RTM Shut-down Period.
For each Settlement Interval, only the RTM Shut-down Cost in a RTM Shut-down Period
is eligible for Bid Cost Recovery. The following rules shall apply sequentially to qualify
the RTM Shut-down Cost in a RTM Shut-down Period:
1. The RTM Shut-down Cost for a RTM Shut-down Period shall be zero if it is
followed by a RTM self commitment period in generation mode or offline mode;
2. The RTM Shut-down Cost for a RTM Shut-down Period shall be zero if it is due to
a SLIC outage;
D.7.4. Business Rules for Cost Calculation for Multi-Stage Generating Resources
Both “commitment type” determination and “AUX” process will be executed at the MSG
Configuration level for Multi-Stage Generating Resources. Below is an outline of the
logic for commitment type determination for resources:
For MSG Configurations pertaining to CAISO Tariff sections 11.8.1.1, 11.8.1.2,
their commitment types will be determined using the existing logic for non MSG
resources described in Section D2, D3, D4 and D6. The application of the
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business rules is based on each individual MSG Configuration’s data with the
following specific rules for MSG Generating Resources:
o During a transition from one configuration to another configuration, the
transition period is considered as part of the “From” MSG Configuration’s
Commitment Period.
o For the “To” MSG Configuration, the commitment period does not include
the transition period. Instead it starts at the end of the transition period.
o For each MSG Configuration, the self-commitment period extension logic
is applicable only when it is active and the resource is online.
o When applying the self commitment period extension rules in D6.2, the
Minimum Run Time and Minimum Down Time for the Multi-Stage
Generating Resource plant level, individual MSG Configuration level, and
the configuration group level will be used.
Pertaining to CAISO Tariff sections 11.8.2.1, 11.8.3.1 and 11.8.4.1, the logic for the BCR
consideration and allocation of the Commitment Costs (Start-Up Cost, Minimum Load
Cost and Transition Cost) is as follows:
The logic in determining/distributing the Minimum Load Cost and Start-Up Cost
for Multi-Stage Generating Resources is the same as that for non-Multi-Stage
Generating Resources except that the Minimum Load Cost and Start-Up Cost will
be allocated to the qualified MSG Configuration’s CAISO Commitment Period..
The rules for BCR qualifications for the MSG Configuration’s CAISO
Commitment Period are shown below.
The Transition Cost will be determined based on whether the “To” MSG
Configuration is CAISO committed or not. The Transition Cost amount is the
Transition Cost registered for the transition related to the “From” MSG
Configuration and “To” MSG Configuration. Transition Cost is allocated to the
CAISO Commitment Period of the “To” MSG Configuration. The rules for BCR
qualifications for the MSG Configuration’s CAISO Commitment Period are shown
below.
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For the MSG Configurations, when starting up from offline to an MSG Configuration, the
Start-Up Cost pertaining to that MSG Configuration applies for BCR qualification, and
there are no Transition Costs applied.. When transitioning between any two MSG
Configurations, since the resources are not offline, the Transition Costs will apply for
BCR qualification, whereas Start-Up Costs will not apply. The rules for BCR
qualifications for CAISO Commitment Period MSG Configurations (applicable to Start-Up
Cost, Minimum Load Cost and Transition Cost), re-stated from the CAISO tariff section
11.8.1.3, are as follows:
For the settlement of the Multi-Stage Generating Resource Start-Up Cost, Minimum
Load Cost, and Transition Cost in the IFM, RUC, and RTM, the CAISO will select the
applicable Start-Up Cost, Minimum Load Cost, and Transition Cost based on the
following rules.
(1) In any given Settlement Interval, the CAISO will first apply the following
rules to determine the applicable Start-Up Cost, Minimum Load Cost, and
Transition Cost for the Multi-Stage Generating Resources. For a Commitment
Period in which the:
(a) IFM Commitment Period and/or RUC Commitment Period MSG
Configuration(s) are different than the RTM CAISO Commitment Period MSG
Configuration, the Multi-Stage Generating Resource’s Start-Up Cost, Minimum
Load Cost, and Transition Cost will be settled based on the RTM CAISO
Commitment Period MSG Configuration Start-Up Cost and Transition Cost as
described in Section 11.8.4.1. Minimum Load Cost will be settled based on the
difference between the RT MSG configuration MLC and the DA MSG
configuration MLC as described in Section 11.8.1.3.
Note that the RT MLC could be negative when the RT Configuration MLC is less
than the DA Configuration MLC.
(b) IFM CAISO Commitment Period and/or RUC CAISO Commitment Period
MSG Configuration(s) and there is a RTM Self-Commitment Period in any MSG
Configuration, the Multi-Stage Generating Resource’s Start-Up Cost, Minimum
Load Cost, and Transition Cost will be settled based on the IFM CAISO
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Commitment Period and/or RUC CAISO Commitment Period MSG
Configuration(s) Start-Up Cost, Minimum Load Cost, and Transition Cost, as
described in Sections 11.8.2.1 and 11.8.3.1, and further determined pursuant to
part (2) of this Section below.
(c) IFM CAISO Commitment Period and/or RUC CAISO Commitment Period
MSG Configuration is the same as the RTM CAISO Commitment Period MSG
Configuration, the Multi-Stage Generating Resource’s Start-Up Cost, Minimum
Load Cost, and Transition Cost will be settled based on the IFM CAISO
Commitment Period and/or RUC CAISO Commitment Period MSG
Configuration(s) Start-Up Cost, Minimum Load Cost, and Transition Cost for the ,
described in Sections 11.8.2.1 and 11.8.3.1, and further determined pursuant to
part (2) of this Section below.
(d) IFM and RUC Self-Commitment Period MSG Configuration(s) are the
same as the RTM CAISO Commitment Period MSG Configuration, then the
Multi-Stage Generating Resource’s Start-Up Cost, Minimum Load Cost, and
Transition Cost will be settled based on the RTM CAISO Commitment Period
MSG Configuration Start-Up Cost, Minimum Load Cost, and Transition Cost for
as described in Section 11.8.4.1.
(2) In any given Settlement Interval, after the rules specified in part (1) above
of this Section have been executed, the ISO will apply the following rules to
determine whether the IFM or RUC Start-Up Cost, Minimum Load Cost, and
Transition Cost apply for Multi-Stage Generating Resources. For a Commitment
Period in which the:
(a) IFM Commitment Period MSG Configuration is different than the RUC
CAISO Commitment Period MSG Configuration than, then the Multi-Stage
Generating Resource’s Start-Up Cost, Minimum Load Cost, and Transition Cost
will be settled based on the RUC CAISO Commitment Period MSG Configuration
Start-Up Cost, Minimum Load Cost, and Transition Cost as described in Section
11.8.3.1.
(b) IFM CAISO Commitment Period MSG Configuration is the same as the
RUC Commitment Period MSG Configuration, the Multi-Stage Generating
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Resource’s Start-Up Cost, Minimum Load Cost, and Transition Cost will be
based on the IFM CAISO Commitment Period MSG Configuration Start-Up Cost,
Minimum Load Cost, and Transition Cost for the, as described in Section
11.8.2.1.
D.7.5. Business Rules Change for Convergence Bidding
Bid Cost Recovery costs related to Short Start Units committed by CAISO in the
Real-Time as a result of awarded RUC capacity will be included in RUC
Compensation Costs. The applicable Trading Hours are those for which the
Short Start Units have a non-zero RUC Award but no Day-Ahead Schedule.
Attachment E
E. Price Corrections Make Whole Payments
The following attachment presents further details in support of the CAISO Tariff section
Price Corrections Make Whole Payments, CAISO Demand and Exports. The following
attachment only describes the mechanism to calculate make whole payments for
physical demand and exports. Although Virtual Bids are also subject to make whole
payment using the same principle as described below, it is performed in a different
fashion. Refer to BPM for Settlement and Billing for the related charge code changes for
Virtual Bid make whole payments.
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Correction Overview
The “Make Whole” payment mechanism is designed to compensate market participants
for adverse financial impacts when prices are corrected in a way that is not consistent
with accepted Demand bids. If the LMP Price Correction team corrects an LMP in the
upward direction that impacts Demand in the Day-Ahead Market or RTM markets such
that the a market participant’s Demand or Export Bid curve becomes uneconomic, then
the CAISO will calculate a Make Whole Price Correction. The Make Whole Price
Correction will be calculated as follows:
The total cleared MWhs of CAISO Demand or Export in the Day-Ahead Schedule
or FMM Schedule, as applicable, multiplied by the Derived LMP (or corrected)
LMP, minus the make-whole payment amount, all of which is divided by the total
cleared MWhs of CAISO Demand or Export in the Day-Ahead Schedule or FMM
Schedule, as applicable.
Specifically, the Make Whole payment amount will be calculated on an hourly basis
determined by the area between the resource’s CAISO Demand or Export Bid curve and
the Derived LMP, which is calculated as the MWhs in each of the cleared bid segments
in the Day-Ahead Schedule or FMM Schedule for the affected resource, multiplied by
the maximum of zero or the corrected LMP (fifteen-minute LMP in the real-time) minus
the bid segment price.
The following summarizes the Make Whole Price Correction:
Day Ahead price corrections performed by the LMP Price Correction team can
render an accepted bid uneconomic.
Supply resources use the Bid Cost Recovery method to recoup any un re-
covered cost
Make Whole will only apply if:
Price increases
Only for the portion of bid rendered uneconomic
Applies to DA Demand and Exports and RTM Exports
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Make Whole Calculation Elements
The elements of the Make Whole Price Correction are described in this section.
Definition of Bid Portion Rendered Uneconomic
For the portion of Bid that is rendered uneconomic, will be charged the equivalent
of “as-bid”, instead of the corrected price. Figures 1 and 2 represent two
examples of Make Whole payments as defined by difference levels of price
corrections and different levels of where their bid is uneconomic:
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
0 100 200 300 400 500 600 700
Demand Bid Curve
(MWh)
($/MWh)
Corrected Price
Original Price
Make-whole
payment
Figure 6. Price Correction from $20 to $80
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
0 100 200 300 400 500 600 700
Demand Bid Curve
(MWh)
($/MWh)
Corrected Price
Original Price
Make-whole
payment
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Figure 7. Price Correction from $20 to $60
Make Whole Price Correction Detailed Examples
Two examples of the Make Whole Price Correction are described in this section.
In Example 1, suppose the DA price is corrected from $23 to $85 and the original bid
was accepted for 500MW, and none of which was economic after price correction. The
following would occur:
Demand resource will initially be set at the new LMP;
The Make Whole Price Correction will calculate how much was “over charged”
(stripped area in Figure 1) and subtracted from settlement with new LMP;
A Derived LMP will be set reflecting the uneconomic portion;
The Derived LMP will be sent to Settlements in CC 6011 (or 6051) and reflected
on the Demand resource’s initial settlement statement.
Figures 3 represents the elements in this example:
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Figure 3. Example 1 Price Correction from $23 to $85 and Bid Curve
Example 1 calculation is performed as follows:
Charge from Ex-post LMP settlement = 300*$85=$25500
If the final energy schedule MW is greater than or equal to the higher end of the
bid segment MW range, then the entire bid segment counts:
Make Whole Payment $ = Max(0, (higher end of bid segment – lower end of the
bid segment) * (Ex-post LMP – bid price))
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Calculate the $ = (50MW-0MW)* ($85-$80) + (100MW-50MW)*($85-$70) +
(150MW-100MW)*($85-$60) + (200MW-150MW)*($85-$50) + (250MW-
200MW)*($85-$40) + (300MW-250MW)*($85-$30)
$9000 = $250+$750+$1250+$1750+$2250+$2750 = Make whole
payment
Settlement minus Make-Whole payment: $25500-$9000 = $16500
Implicit LMP = $16500/300MW = $55/MW
In Example 2, suppose the DA price is corrected from $23 to $55 and the original bid
was accepted for 500MW, and only a portion of which was economic after price
correction. The following would occur:
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Figure 4. Example 2 Price Correction from $23 to $55 and Bid Curve
Example 2 calculation is performed as follows:
Charge from Ex-post LMP settlement = 300*$55=$16500
If the final energy schedule MW is less than the higher end of the bid segment
MW range, then only the range between the lower end and the schedule MW
counts,
Make Whole Payment $ = Max(0, (Final schedule MW – lower end of the bid
segment MW) * (Ex-post LMP – bid price))
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Calculate the $ = (200MW-150MW)*($55-$50) + (250MW-200MW)*($55-$40) +
(300MW-250MW)*($55-$30)
$2250 = $250+$750+$1250 = Make whole payment
Settlement minus Make-Whole payment: $16500-$2250 = $14250
Implicit LMP = $14250/300MW = $47.50/MW
Make Whole Publishing and Reporting
Details on the publishing of Make Whole Corrections are described in this section.
The correction Make Whole price will be available on OASIS for the given Pnode.
This is posted at T+5 as part of the existing T+5 price correction process.
CMRI will display the Derived LMP at the resource level. This will also be
available at T+5.
In Settlements, (CC6011 or 6051), the Derived LMP shall be utilized on the initial
Settlement Statement.
An aggregation by market of the correction amounts will be provided on the existing Monthly Market Performance Report. The report is located at http://www.caiso.com/2424/2424d03b3f610.html.
CAISO Business Practice Manual BPM for Market Operations
Attachment F
CRR Settlement Rule
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F. CRR Settlement Rule
The following attachment presents further details in support of the CAISO Tariff section
11.2.4.6.
F.1 Overview
The following “flow-based” approach was designed to provide a targeted way of limiting CRR payments to entities that are also Convergence Bidding Entities when Virtual Awards may increase their CRR payments. It has the following general features:
Allows netting of results across all hours of each day corresponding to the entity’s CRRs. Specifically, for peak period CRRs, results will be netted across hours 7 to 22, while results will be netted across hours 1 to 6 and 23 to 24 for off-peak CRRs.
For each congested constraint that is found to be affected by the entity’s Virtual Awards, the methodology will consider the aggregate (net) impact of this congestion on all of the entity’s CRRs during each hour.
The equations for calculating the impact of Virtual Awards on market flows exclude Virtual Awards at any Default Load Aggregation Point (DLAP) and Trading Hub , since it is unlikely that it would be feasible or profitable for an entity to significantly impact its CRR revenues (or payments) through virtual bidding at the DLAP or Trading Hub level.
Specific treatment for “counter flow” CRRs (i.e., CRRs in the opposite direction of congestion that require the CRR Holder to pay congestion costs).
Section F.2 describes the CRR Settlement Rule.
F.2 CRR Settlement Rule
In the following CRR settlement rules, the term of “entity” is referring to the CRR Holders
that are also Convergence Bidding Entities.
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Step 1. Calculate combined impact of entity’s portfolio of Virtual Awards on flows of constraint for each Trading Hour
Start by considering a constraint, k, which was binding in the Integrated Forward Market (IFM), the relevant Real-Time Market, or both.9 Also consider an entity, i, who owns a
portfolio of time period, p, CRRs ( ipC , ). The time period, p, specifies whether the
CRR, ipCc , , is for the peak or off-peak set of hours. The first step in determining the
CRR settlement rule payment adjustment for entity, i, with respect to constraint, k, over period, p, is to calculate the combined impact of the entity i's portfolio of Virtual Awards on the IFM flows of constraint, k, for each hour, t, in the time period, p. The total megawatt (MW) flow contribution from all the Virtual Awards of the entity CRR Holder to the total MW flow on constraint, k, is calculated as follows:
tiJj
itjtjkDAitkDA VBSF,
,,,,,,,,
Where:
tjkDAS ,,, is the IFM shift factor of constraint k with respect to Virtual Awards at node j
during hour t,
tiJ , is the set of all nodes at which entity, i, has Virtual Awards for the hour t, and
itjVB ,, is the volume (MW) of Virtual Awards of the entity at node j. itjVB ,, excludes
Virtual Awards at any DLAP and Trading Hub. This exclusion is provided since it is unlikely that it would be feasible or profitable for an individual entity to significantly impact its CRR revenues (or payments) through virtual bidding at the DLAP or Trading hub level. This exclusion also creates a “safe harbor” for entities with CRRs to participate in virtual bidding without the risk of triggering this CRR settlement rule’s
payment adjustment. Virtual Supply Awards are represented as positive values of itjVB ,,
while Virtual Demand Awards are represented as negative values of itjVB ,, . All the shift
factors are based on the default slack (load distributed slack).
If the constraint is binding in the RTM, but not in the IFM, then the average over the hour of the real-time shift factors for a node will be used in place of the day-ahead shift factors.
9 Constraints that are binding in the Real-Time Market but not in the IFM must be considered in order to adjust payments from/to holders of CRRs who may use Virtual Bids to profit from the elimination of Congestion on a constraint in the IFM.
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Step 2. Determine hours where entity’s portfolio of Virtual Awards significantly impacted constraint
The next step is to compare the net impact of the entity’s portfolio of Virtual Supply and
Demand Awards ( itkDAF ,,, ) to the total flow on the constraint for each Trading Hour. A
threshold percentage (L,) of the constraint’s flow limit (K) is used to determine if congestion on the constraint may have been significantly impacted by the CRR Holder’s Virtual Awards over Trading Hour, t. Specifically, the constraint’s impact on the value of the entity’s portfolio of CRR holdings will be considered in Step 3 for hours, t, where
itkDAF ,,, passes two criteria:
A) Is itkDAF ,,, in the direction that would increase the value of the entity’s
CRR portfolio?
The general statement of the criteria for a Trading Hour passing this Step 2A, is if
itkDAF ,,, is in the same direction as tkDAF ,, (whether direction of flow is identified by sign
or by a flag in a separate column), then tkDAitkDA FF ,,,,, * is positive, and if itkDAF ,,, is in
the opposite direction of tkDAF ,, , then tkDAitkDA FF ,,,,, * is negative. With this general
definition, the equation
0**,
,,,,,,,,,,
ipCc
tckRTitctkDAitkDA QFF (terms defined in step 3
below) will identify that the entity’s portfolio of Virtual Awards were in the direction to increase the value of the entity’s CRR portfolio at hour, t. If k is binding in the IFM but
not in any interval of the appropriate RTM, (that is, if 0,,, tckRT ) then the direction of
flow test will be if
0**,
,,,,,,,,,,
ipCc
tckDAitctkDAitkDA QFF . If the direction of flow on the
constraint changes between DAM and RTM, then similar equations will determine if the Entity’s Virtual Awards were in the direction to increase the value of the CRR portfolio.
B) Is tkDAitkDA FKLKF ,,,,, *
Where tkDAF ,, is the total IFM flow on constraint, k, during Trading Hour, t.
If the flow impact of the entity’s Virtual Award is in the direction to increase the value of the entity’s CRR portfolio (Step 2A), then Step 2B identifies if the magnitude of that flow impact was sufficiently large. L is a parameter set to .10 (10 percent) for all constraints as specified in Tariff section 11.2.4.6(b). Based on actual operating experience and off-line studies of the potential price impacts resulting from different levels of Virtual Awards, the threshold L may be adjusted for some or all constraints.
The result of Step 2 is the definition of the set ipkT ,, as the set of hours, t, in time
period, p, that pass Step 2A and Step 2B. Step 2 identifies the hours where the entity’s Virtual Award may have significantly impacted the shadow price of constraint, k; the Virtual Award, therefore, may have had a significant positive impact on the value of the entity’s CRR portfolio.
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Step 3. Compare constraint’s impact on day-ahead value of entity’s CRR portfolio to the constraint’s impact on real-time value of entity’s CRR portfolio
In order to determine the CRR settlement rule payment adjustment for entity, i, and constraint, k, for the time period, p, start by determining the constraint’s contribution to the difference between the day-ahead value and real-time value of one of the entity’s CRR holdings for one Trading Hour, t, that passed Step 2:
source
H
h
htkRThtSourcekRT
k
H
h
htkRThtSinkkRT
tckRT
tkDAtSourcekDAtkDAtSinkkDAtckDA
tckRTtckDAitcitck
H
S
H
S
SS
Qd
source
source
sourcesourcec
k
k
kkc
cc
,,,,,,,
sin
,,,,,,,
,,,
,,,,,,,,,,,,,
,,,,,,,,,,,
sin
sin
sinsin
:Where
*
itcQ ,, is the MW quantity of CRR, c, owned by the entity for Trading Hour, t.
tSinkkDA cS ,,, is the IFM shift factor of constraint k with respect to the sink node of c.
tkDA ,, is the shadow price of the constraint k in the IFM for Trade Hour, t.
h designates the 15-minute interval during each Trading Hour, thus H=4 intervals for
each Trading Hour. tckDA ,,, is the constraint k’s contribution to the CRR’s per MW “day-
ahead” value for hour, t, and tckRT ,,, is the constraint k’s contribution to the CRR’s per
MW “real-time” value for hour, t.
Finally, in order to determine the constraint’s impact on the value of an entity’s CRR
portfolio for the time period, p, add its impact on each CRR, ipCc , , for all Trading
Hours ipkTt ,, . Specifically, the constraint’s impact on the value of an entity’s CRR
portfolio for the time period, p, is:
ipk ipTt Cc
itckipk d,, ,
,,,,,
Step 4. Apply CRR payment adjustment
If over the Trading Day, the constraint contributed to the day-ahead value of the entity’s CRR portfolio’s exceeding the real-time value of the entity’s CRR portfolio
( 0,, ipk ),entity i's CRR payment will be charged ipk ,, . If 0,, ipk , there will not be a
CRR settlement rule payment adjustment for entity, i, with respect to constraint, k, for period, p. A payment adjustment will be calculated for an entity for each constraint, time period, and day. Specifically, the CRR settlement rule will calculate the following daily payment adjustments for CRR Holders:
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0,max ,,,, ipkipkPA
If the entity has more than one SCID that is used for CRRs, the payment adjustment will have to be distributed amongst them. The following algorithm will be used to distribute
the total payment adjustment for i, ipkPA ,, , amongst the entity’s various CRR-mapped
SCIDs.
1. Perform all Step 3 and Step 4 calculations by SCID. Let sipkOPA ,, denote the payment
adjustment for SCID, is’s, CRR portfolio according to the Step 3 and 4 calculations.
2. If 00 ,,,, ss ipkipk FPAOPA where
sipkFPA ,, denotes the “final” payment adjustment
charged to SCID is
3. if SiOPA sipk s 0,, where{S} is the set of SCIDs, i’s SCIDs that would get a
charge (as opposed to a credit) under Step 3.
4. Let
Si
ipk
s
sOPAG ,,
5. G
OPAR s
s
ipk
i
,,
6. ipkiipks PARFPASiss ,,,, *,
F.3 CMRI Data Publications
Market SCs can review data contributing to the CRR Settlement Rule on CMRI via three reports. Please refer to the Market Instruments BPM, Section 10 for details on these reports.
F.4 CRR Settlement Rule for Circular Schedule
The following presents further details in support of CAISO Tariff section 11.2.4.7.
The following approach was designed to provide a targeted way of limiting CRR payments to entities that may increase their CRR payments or reduce their CRR obligations through circular schedules.
The process flow for the CRR Settlement for circular schedules in the IFM market is described below:
Identify circular schedules subject to settlement rule in section 11.33 of the CAISO
Tariff that have scheduled MW in IFM market.
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The data used for CRR Settlement Calculation:
a. Positive Power Transfer Distribution Factor (PTDF) Data from EDR
Production
b. Shadow Price Data from EDR Production
c. Circular Schedule MW.
Start by considering constraint I, which was binding in the IFM market. Also consider
an entity, k who owns a CRR portfolio of time period t. The first step in determining
the CRR Settlement rule is to calculate the impact of the entity k’s circular schedules
on the IFM flows of constraint I, for each hour in the time period t.
Determine whether CRR holder is receiving payment or faces obligations from CRRs
for the constraint I. If CRR holder is receiving payment or would face reduced
obligations from CRRs for the congested constraint I, then CRR Settlement would
apply.
The total MW flow contribution from the segments of circular schedules of the entity
CRR holder to the total MW flow on constraint I is calculated as follows:
)_,min(*)0,max(,
,,,,,,,, InjCRRMWSFFtkJj
ktjtjiIFMktiIFM
Where tjiIFMSF ,,, is the positive PTDF of constraint I at node j during time t in the
direction of CRRs,
ktjMW ,, Is the circular schedule of entity k during time t
The Settlement rule for circular schedules in dollars would be calculated as:
tkJj
tIFMktiIFMktiIFM FCBA,
,,,,,,,
Where ktiIFMCBA ,,, is the Settlement amount for circular schedules for constraint I for time period t,
tIFM , is the shadow price in IFM of the congested element for time period t.
CAISO Business Practice Manual BPM for Market Operations
Attachment G
PROCESS FOR ADDRESSING
MARKET ISSUES
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G. Process for Addressing Market Issues 1. Reporting of Market Issues
1.1. In the event that the ISO discovers a possible Market Issue,10 the ISO will
conduct a preliminary investigation and evaluation of the issue to
determine whether a Market Issue has occurred. If the ISO determines
that it is probable that a Market Issue did occur, as soon as reasonably
practicable, the ISO will notify the ISO Department of Market Monitoring
(DMM).
1.2. If the ISO determines that there is sufficient reliable information to believe
that it is probable that a Market Issue occurred the ISO, in collaboration
with DMM as appropriate, will conduct a preliminary analysis of the
probable Market Issue.
1.3. If the ISO further confirms the observed event(s) consist(s) of a Market
Issue, to the extent that communication of the existence of the Market
Issue does not pose a breach of confidentiality and does not potentially
create incentives for adverse market behavior, the ISO will communicate
to Market Participants the occurrence of the Market Issue and a
description of the issue as known at that time, as soon as reasonably
practicable. This communication is likely to occur through the ISO’s
market related participant conference calls, but may also occur through
market notices. To the extent that the Market Issue only affects specific
market participants and does not affect the market as whole, the ISO will
communicate separately with the affected Market Participants.
1.4. As soon as reasonably practicable after the ISO makes a communication
as described in Section 1.3, based on the significance of the issue and
whether there is a material market impact, the ISO may post on its
website a Market Issue Bulletin that will include the information discussed
10 A Market Issue consists of but is not limited to market design flaws, software implementation and modeling anomalies or errors, market data anomalies or errors, and economic inefficiencies that have a material effect on the CAISO Markets. Market Issues may relate to, but are handled separately from: 1) Energy or Ancillary Services prices found to be erroneous and corrected pursuant to the price correction process within the Price Correction Time Horizon as described in Section 8 of the BPM for Market Operations; or 2) Market Participant disputes managed through the Settlements dispute process described in Section 11 and 13 of the ISO Tariff.
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in Section 1.5. The ISO will endeavor to post the Market Issue Bulletin
within one-hundred and eighty (180) days after the communication
specified in Section 1.3. In the event that the ISO is not able to complete
the report within one-hundred and eighty (180) days, the ISO will post a
status report on the one-hundred and eightieth (180th) day with an
expected completion date.
1.5. Subject to the confidentiality restrictions, the Market Issue Bulletin will
include, as appropriate:
1.5.1. A description of the Market Issue and tariff implications as
appropriate, as described further in Section 2.
1.5.2. A description of the time frame involved.
1.5.3. A description of financial effects of the Market Issue, as described
further in Section 2.
1.5.4. In the event that the Market Issue impacts ISO Market prices for
which the Price Correction Time Horizon as described in Section 8 of
the Business Practice Manual for Market Operations has expired, the
ISO will identify the impacted ISO Market prices in the Market Issue
Bulletin. The ISO also will identify whether there is good cause to
consider correcting such prices. The determination of good cause will
be based on the assessment, to the extent feasible, of the impact on
the market as a whole, the impact to individual Market Participants
and sectors of the market, and on the feasibility and administrative
burden of resettling based on the prices if they were to be corrected.
1.5.5. A description, including a time table as appropriate, of steps
planned or taken to address the Market Issue.
1.5.6. A description of any necessary tariff revisions or any other requests
for relief the ISO intends to pursue with the Federal Energy
Regulatory Commission, if applicable, as described in section 3.
2. Analysis of Probable Market Issue
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The depth and scope of any analysis conducted by the ISO will depend on the feasibility of conducting a viable cause and financial analysis that provides meaningful results. For example, in some instances it may not be technically feasible to actually replicate market outcomes via an alternative method or approach, in which case any feasible evaluation may be limited to mere estimates based on limited information and not actual market results. Also, in some cases while it may be technically feasible to replicate the market outcome to evaluate the cause and financial impact, doing so may be so administratively burdensome as to render the analysis impractical. The ISO will evaluate these factors on a case by case basis to determine the optimal level of analysis and will explain any limitations of the analysis conducted and an assessment of the feasibility and administrative burden of potential remedies if appropriate.
2.1. Market Issue Analysis. In the event that the ISO identifies a Market
Issue, the ISO will investigate and analyze the observed market results
and processes that are affected by the Market Issue. This analysis will
serve as the basis for the ISO’s actions to remedy the issue both from a
regulatory and production perspective. The conclusions of this analysis,
subject to confidentiality requirements and provided the disclosure of the
information does not potentially provide incentives for adverse market
behavior, will be included in the Market Issue Bulletin as discussed in
Section 1.5 above.
2.2. Financial effect. The CAISO will perform an analysis of the financial
effect of the Market Issue. To the extent feasible and practicable, this
analysis will be based on a number of factors including: the number of
impacted intervals, the number of impacted market participants, and the
value impact to market participants, as feasible.
3. ISO Actions
In the event that the ISO determines that a Market Issue exists, based on all
known and reliable information, the ISO will determine whether or not good
cause exists to seek regulatory relief from the Federal Energy Regulatory
Commission, including but not limited to a waiver of the applicable ISO Tariff.
3.1. Regulatory Actions
In the event that the ISO determines to seek regulatory relief from the Federal Energy Regulatory Commission, including but not limited to a waiver of the applicable ISO Tariff, if feasible, the ISO will inform its stakeholders of this intent through the Market Issue Bulletin discussed in Section 1.5 above, or
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through a Market Notice. To the extent permissible and practical given the circumstances of the Market Issue, the ISO will then solicit comments regarding its intended course of action prior to submitting the appropriate pleadings with the Federal Energy Regulatory Commission. In such cases, the ISO will subsequently seek appropriate regulatory relief to implement adjustments.
3.2. Non-Regulatory Actions
In the event that the ISO determines not to seek regulatory relief from the
Federal Energy Regulatory Commission, if feasible, the ISO will inform its
stakeholders of this intent through the Market Issue Bulletin discussed in
Section 1.5 above, or through a market notice. In such cases, the ISO will
subsequently implement adjustments deemed appropriate and as permitted
pursuant to or consistent with the ISO tariff to address the Market Issue.
CAISO Business Practice Manual BPM for Market Operations
Attachment H
Circular Schedule
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H. Circular Schedule Rule
The following attachment presents further details in support of the CAISO Tariff section
11.33 and 30.5.5
H.1 Overview
This document provides explanation of the settlement implications from engaging in a
prohibited practice known as “circular scheduling.” Circular scheduling refers generally
to the delivery of market import and export schedules that have a source and sink in the
same balancing authority area. Such schedules typically would involve transmission
segments in a second balancing authority area.
One type of circular schedule is illustrated through an example below. This example
consists of a market schedule to import power to the ISO using one intertie and export
this power at another intertie. In this case, an export is scheduled to Node B, and an
import is scheduled from Node C back to ISO. Node C can be in a different balancing
authority area than Node B.
Node B
Node C
CAISO
Outside ISO
Intertie 1
Intertie 2
The actual circular nature of the combined import and export schedules awarded in the
ISO markets is not apparent based only on review of the bids or self-schedules
submitted in the ISO markets. Rather, it is necessary for the ISO to review the
corresponding e-Tags to confirm that the entity procured external transmission and thus
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created a closed loop of energy. The e-tags show the energy schedules exported from
the ISO actually being scheduled on the transmission market outside the ISO (from
Node B to Node C).
The power scheduled for export from the ISO would be returned on a transmission
network outside the ISO back to the ISO causing the circular schedules to not produce
actual flow of power. However, a market participant could profit from the circular
schedules by earning the price difference between the points at which the energy was
scheduled to be imported to, and exported from, the ISO.
Section F.2 describes how one type of circular schedule is addressed in the ISO
markets.
H.2 Circular Schedule Rule
The purpose of the circular schedule settlement rule is to negate the incentive to submit
bids (including self-schedules) that would lead to such transactions. Specifically, the
import portion of a prohibited circular schedule will be settled at the lower of the: (a) LMP
of the scheduling point for the import portion of the schedule in the market in which the
import portion of the schedule was awarded; or (b) LMP of the scheduling point for the
export portion of the schedule in the market in which the export portion of the schedule
was awarded.
The process flow for identifying prohibited circular schedules and applying the settlement
rule is described below:
Identify all single scheduling coordinator circular schedules sourcing and sinking in
the same balancing authority area.
Identify single scheduling coordinator circular schedules meeting the following
exceptions. If one of these four conditions is met then the schedule will not be
subject to the settlement rule. If the exception were removed from consideration and
the resulting hypothetical schedule could have an E-Tag reflecting a source and sink
in the same BAA, then the circular schedule will still be subject to the settlement rule:
a. The circular schedule includes a transmission segment on a DC Intertie.
b. The circular schedule involves a Pseudo-Tie generating unit delivering
energy from its Native Balancing Authority Area to an Attaining Balancing
Authority Area.
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c. The circular schedule is used either to: (i) serve Load that temporarily has
become isolated from the CAISO Balancing Authority Area because of an
Outage; or (ii) deliver Power from a Generating Unit that temporarily has
become isolated from the CAISO Balancing Authority Area because of an
Outage.
d. The circular schedule involves a Wheeling Through transaction that the
Scheduling Coordinator can demonstrate was used to serve load located
outside the transmission and Distribution System of a Participating TO.
i. To qualify for this exception, the ISO will require that a representative
of the Scheduling Coordinator with the authority to bind the
company provide a signed document attesting to the fact that the
company serves load at the location that will be the ultimate sink of
the wheel. The ISO will then provide the entity with a special
resource ID to use for scheduling the wheel. If the e-Tag for a
wheeling transaction reflects such a resource ID as the sink of the
transaction, then the ISO’s systems will be configured not to apply
the settlement rules.
Compare the output IFM and FMM bid LMPs for the respective schedules
Settle the Import to the ISO at the lower of LMPs at scheduling points for import and
export for the MW in IFM and FMM
Calculate the profit by computing the differences in prices between import and export
with the circular schedules in the market in which the import was scheduled.
The total profit is computed by taking the difference of export settlements and import settlements.
For FMM Profit:
)*)(()*)(( 1,, TFMMRTMlastFMMRTM PRICEMWPRICEMW
For DA Profit:
)*)(()*)(( 1,, TIFMIFMlastIFMIFM PRICEMWPRICEMW
Where HASPMW is the circular schedule MW in FMM market.
lastFMMPRICE , is the price in FMM for the last segment, similarly 1,TFMMPRICE is the
cleared price in FMM market for the schedules of the first segment.
Compare the output IFM and FMM bid LMPs for the respective schedules
Settle the Import to the ISO at the lower of LMPs at scheduling points for import and
export for the MW in IFM and FMM
Calculate the profit by computing the differences in prices between import and export
with the circular schedules in the market in which the import was scheduled.
The total profit is computed by taking the difference of export settlements and import settlements.
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For FMM Profit:
)*)(()*)(( 1,, TFMMRTMlastFMMRTM PRICEMWPRICEMW
For DA Profit:
)*)(()*)(( 1,, TIFMIFMlastIFMIFM PRICEMWPRICEMW
Where HASPMW is the circular schedule MW in FMM market.
lastFMMPRICE , is the price in FMM for the last segment, similarly 1,TFMMPRICE is the
cleared price in FMM market for the schedules of the first segment.
CAISO Business Practice Manual BPM for Market Operations
Attachment I
Implementation of Marginal Cost of Losses and Transmission Losses for Facilities on the CAISO
Controlled Grid outside the CAISO Balancing Authority Area
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I. Implementation of Marginal Cost of Losses and Transmission Losses for Facilities on the CAISO Controlled Grid outside the CAISO Balancing Authority Area 1. Background
This attachment is based on CAISO Tariff Section 27.1.1.2.
Section 27.1.1.2 provides in part that:
For CAISO Controlled Grid facilities outside the CAISO Balancing Authority Area, the CAISO shall assess the cost of Transmission Losses to Scheduling Coordinators using each such facility based on the quantity of losses agreed upon with the neighboring Balancing Authority multiplied by the LMP at the PNode of the Transmission Interface with the neighboring Balance Authority Area.
For the purposes of this discussion, facilities that are on the CAISO Controlled Grid but are not in the CAISO Balancing Authority Area (CAISO BAA) are referred to herein as the Subject Facilities. Section 27.1.1.2 ensures that scheduling coordinators are only charged for losses attributed to schedules coming to the CAISO BAA through Subject Facilities based on the quantity of losses agreed upon with the neighboring Balancing Authority multiplied by the LMP at the PNode of the Transmission Interface with the neighboring Balancing Authority Area.
This provision also ensures that the CAISO does not charge for the marginal cost of losses (MCL) that reflects the resistive component of the losses on the Subject Facilities to schedules that use the Subject Facilities. The LMP at such locations will only reflect a MCL for the CAISO Controlled Grid that is in the CAISO BAA and will not reflect the MCL on the Subject Facilities outside the CAISO BAA.
2. Implementation
The location for the calculation of the Transmission Losses must be selected at a Location where the external BAA ends and the CAISO BAA begins for that power flow. This is based on the presumption and operational practice that the external BAA is accounting for losses on the Subject Facilities, and not the CAISO. In order to calculate losses at the correct location consistent with this requirement, the CAISO uses the tie location at which losses are scheduled back to the neighboring Balancing Authority Area. The external tie point loss matrix shown below provides a mapping of such locations depending on where the schedule is submitted to enter into the CAISO Controlled Grid.
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The MCLs calculated for Locations within the CAISO Balancing Authority
Area shall not reflect the cost of Transmission Losses on Subject Facilities.
Because of this requirement, the CAISO calculates the LMPs for such
transactions by zeroing out the resistive component for power flows on the
Subject Facilities. This provision does not preclude the CAISO from applying
the MCLs attributed to such power flows on the CAISO Controlled Grid that is
within the CAISO BAA. Therefore, the Marginal Cost of Losses of the LMP
for transactions using the Subject Facilities is based on the same “border
location” approach. In summary, the CAISO calculates an LMP that includes
a MCL based on the assumption that the power is physically injected at the
CAISO border with the neighboring BAA who is owed the losses. This is
accomplished by calculating an LMP that is derived by replacing the MCL
component of the original LMP, with a MCL component from the LMP at the
injection location on the border of the CAISO BAA.
Note that the above loss adjustments will be made only to the resource
specific prices and not to the nodal prices in OASIS. Market participants will
be able to validate their settlements statements with CMRI reports.
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Scheduling Points Matrix
Balancing Authority
Scheduling Point TNAME
Scheduling Point Pnode TNAME Border Border PNode
APS Four Corners FOURCORNE345 FOURCORN_5_N501 NORTHGILA69 NGILA1_5_N001
APS Moenkopi MOENKOPI500 MOENKOPI_5_N101 NORTHGILA69 NGILA1_5_N001
LDWP Gonder GONIPP GONDER_2_N501 SYLMAR SYLMARLA_2_N501
LDWP Intermountain IPP INTERM1G_7_N501 SYLMAR SYLMARLA_2_N501
LDWP Intermountain IPPUTAH INTERMT_3_N506 SYLMAR SYLMARLA_2_N501
LDWP Marketplace 500 MARKETPLACE MARKETPL_5_N501 SYLMAR SYLMARLA_2_N501
LDWP McCullough 500 MCCULLOUG500 MCCULLGX_5_N501 SYLMAR SYLMARLA_2_N501
LDWP Mona MDWP MONA_3_N501 SYLMAR SYLMARLA_2_N501
LDWP NOB NOB SYLMARDC_2_N501 SYLMAR SYLMARLA_2_N501
WALC Mead 230kv MEAD2MSCHD MEADN_2_N501 MEAD230 MEADS_2_N101
WALC Mead 500kv MEAD5MSCHD MEAD_5_N501 MEAD230 MEADS_2_N101
WALC Westwing 500 WESTWING500 WESTWING_5_N501 MEAD230 MEADS_2_N101
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Formatted: Font: 8 pt, Not Italic
3. Example
The following example demonstrates how the LMP is calculated for external tie point transactions based on the matrix above.
A market participant schedules an import transaction at Westwing 500 using ‘SCID_WESTWING500_I_F_123456’ resource ID.
Scheduling Point PNode
Border Point PNode
WESTWING_5_N501 MEADS_2_N101
Energy: 25 Energy: 25
Congestion: 8 Congestion: 2
Loss: -1 Loss: 3
LMP: 32 LMP: 30
The resource’s LMP will be constructed using the energy and congestion components of the scheduling point PNode, and the marginal cost of losses from the border PNode for any scheduled transaction.
Resource Specific Price
SCID_WESTWING500_I_F_123456
Energy: 25
Congestion: 8
Loss: 3
LMP 36
CAISO Business Practice Manual BPM for Market Operations
Attachment J
Calculation of Weekly Mileage Multipliers
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J. Calculation of Weekly Mileage Multipliers
J.1 Introduction
Procurement of the regulation up and regulation down ancillary services is based on a
capacity requirement and a Mileage requirement. The Mileage requirement represents the
expected amount of system-wide generation travel required to provide the service. For each
hour, the Mileage requirement is calculated as the minimum of three quantities, one of which
is the product of each regulating service’s capacity requirement and a System Mileage
Multiplier. The System Mileage Multiplier is the amount of total expected resource
movement (up or down), or Mileage, from 1 MW of Regulation Up or Down capacity,
respectively.
Resources certified for Regulation Up or Down have a resource-specific Mileage Up or
Down multiplier. The resource-specific Mileage multiplier is used by the market in
determining the maximum Mileage a resource could be awarded.
This attachment describes the process for calculating the System Mileage Multipliers and
resource-specific Mileage multipliers.
J.2 System Mileage Multiplier
The CAISO calculates hourly system Mileage multipliers from the actual Mileage over the
prior 7 days for each hour. The CAISO performs the calculation by summing the total
Mileage from all resources over the 7-day period for a given hour and dividing by the
Regulation capacity procured in that 7-day period in that hour. For example, in Table 1
below, the System Mileage Multiplier that will be used for HE 08 of the next Friday would be
3.61.
Table 1 – Example of calculation of System Mileage Multiplier for HE 08
A resource’s hourly total Mileage Up or Down is the total movement while on Regulation.
Each Mileage increment is the absolute change in Automatic Generation Control set points
above or below the Dispatch Operating Points between 4 second intervals, with some
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adjustment for underperformance. A total movement is then calculated as the total of the
Automatic Generation Control set point changes over a 15-minute period. An hourly value is
calculated as the sum of four 15-minute periods applicable to the hour.
J.3 Calculation of resource specific Mileage multipliers
The resource-specific Mileage multiplier is based upon historical accuracy and the certified
ramp capability. The resource-specific expected Mileage quantity that is dependent on the
resource’s operational characteristics is calculated as follows:
Table 2 - An Example of Calculation of Resource-Specific Mileage Multiplier
The relative ramp capability (10/A3) allows faster resources to be awarded additional
Mileage. Since all regulation capacity is certified using a 10 minute ramp, the relative ramp
capability allows a resource that can reach its full certified capacity sooner to be awarded
additional Mileage. In the example above, if we assume a resource can reach 20 MW in 4
seconds (round to 1 minute) and a second resource can reach its certified capacity in 9.5
minutes (round to 10 minutes), the faster resource can be awarded ten times more mileage
per 1MW of regulation capacity compared to the slower resource. The value A3 is based on
the best Operational Ramp Rate curves registered in the Master File.
The relative accuracy of a resource compared to the system accuracy from the prior 7 days
(A4/A2) allows more accurate resources to be awarded more Mileage per 1MW of regulation
capacity than less accurate resources. As illustrated above, when both the fast resource and
the slow resource have better accuracy than the system accuracy from the prior 7 days, both
resources have a resource-specific Mileage multiplier greater than the system wide Mileage
multiplier.
The ISO will calculate a resource’s Historic Regulation Performance Accuracy (A4) based on
a rolling thirty day simple average of 15 minute accuracy measurements. Separate accuracy
calculations will be made for Regulation Up and Regulation Down. For newly certified or
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recertified resources, it shall be set initially to the average 30-day Historic Regulation Up
Performance Accuracy among all certified resources. The last calculated value shall be
retained when the resource has not been scheduled for regulation up during the period of
the rolling 30 days at all. The CAISO will sum a resource’s Automatic Generation Control
set points for each four (4) second Regulation interval every fifteen (15) minutes and then
sum the total deviations from the Automatic Generation Control set point for each four (4)
second regulation interval during that fifteen (15) minute period, to compare the two for
calculating a 15-minute accuracy.
For purposes of its accuracy calculations, the ISO will count only those 4 second intervals in
which the ISO provides a resource with an Automatic Generation Control signal to move in
an up or down direction. The ISO will exclude those 4 second intervals from its accuracy
measurements in which the ISO signals a resource to maintain operation at or near their last
dispatch operating point. Accordingly, for the Regulation Up accuracy calculation, the ISO
will only count four (4) second intervals in which the Automatic Generation Control set point
value is higher than the dispatch operating point by a value equal to or greater than the
maximum of 0.1 percent of the resource’s Regulation Up award or 0.1 MW. The ISO will still
calculate instructed mileage for these intervals regardless of the tolerance band. For the
Regulation Down accuracy calculation, the ISO will only count four (4) second intervals in
which the Automatic Generation Control set point is lower than the dispatch operating point
by a value equal to or greater than maximum of the 0.1 percent of the resource’s Regulation
Down award and 0.1 MW. The ISO will still calculate instructed mileage for these intervals
regardless of the tolerance band.
In the event that no Mileage occurs in a fifteen minute interval, the ISO will not include the 15
minute interval in calculating the resource’s historical accuracy
The system wide accuracy numbers (A2) for Regulation Up and Regulation Down is a 7-day
rolling average of the historical accuracy of all resources providing Regulation Up and
Regulation Down, respectively.
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